PDC 2003-A LP - FORM 10-K - October 12, 2010

Attached files

file	filename
EX-31.2 - EXHIBIT 31.2 - PDC 2003-A LP	ex31_2.htm
EX-31.1 - EXHIBIT 31.1 - PDC 2003-A LP	ex31_1.htm
EX-99.2 - EXHIBIT 99.2 - PDC 2003-A LP	ex99_2.htm
EX-32.1 - EXHIBIT 32.1 - PDC 2003-A LP	ex32_1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 000-50615

PDC 2003-A Limited Partnership

(Exact name of registrant as specified in its charter)


West Virginia	51-0452053
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

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

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Title of Each Class

Limited Partnership Interests

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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 and (2) has been subject to such filing requirements for the past 90 days. Yes o No þ

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 o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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 o	Accelerated filer o

Non-accelerated filer o	Smaller reporting company þ

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter:

There is no trading market in the Partnership’s securities. Therefore, there is no aggregate market value.

As of June 30, 2010, the Partnership had 424.15 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2003-A LIMITED PARTNERSHIP

INDEX TO REPORT ON FORM 10-K

		Page
	PART I

	Explanatory Note to This Comprehensive Annual Report	1
	Special Note Regarding Forward-Looking Statements	1
Item 1	Business	3
Item 1A	Risk Factors	17
Item 1B	Unresolved Staff Comments	17
Item 2	Properties	17
Item 3	Legal Proceedings	17
Item 4	[Removed and Reserved]	17

	PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	18
Item 6	Selected Financial Data	20
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	34
Item 8	Financial Statements and Supplementary Data	34
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	35
Item 9A(T)	Controls and Procedures	35
Item 9B	Other Information	38

	PART III

Item 10	Directors, Executive Officers and Corporate Governance	39
Item 11	Executive Compensation	43
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	44
Item 13	Certain Relationships and Related Transactions, and Director Independence	44
Item 14	Principal Accountant Fees and Services	46

	PART IV

Item 15	Exhibits, Financial Statement Schedules	47

Signatures		48

Financial Statements		F-1

Index

PART I

Explanatory Note to This Comprehensive Annual Report

PDC 2003-A Limited Partnership (the “Partnership” or the “Registrant”), which was formed on June 3, 2002 and funded on April 30, 2003, filed a Comprehensive Annual Report on Form 10-K for the years ended December 31, 2007, 2006 and 2005 on October 8, 2010. The report included condensed quarterly unaudited financial statements for each of the applicable quarters in 2007, 2006 and 2005.

This Comprehensive Annual Report on Form 10-K for the years ended December 31, 2009 and 2008 is the first periodic report the Partnership has filed with the Securities and Exchange Commission, or SEC, since the filing of the previously mentioned Comprehensive Annual Report on Form 10-K for 2007-2005. The financial information presented in this Annual Report on Form 10-K includes audited financial statements for the years ended December 31, 2009 and 2008 as well as unaudited condensed financial statements for each applicable interim period in 2009 and 2008. The Partnership has not filed Form 10-Qs for the quarterly periods ended March 31 and June 30, 2010.

Special Note Regarding Forward-Looking Statements

This Annual 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 (the “Exchange Act”) regarding PDC 2003-A Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business, financial condition and results of operations. Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership.

All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. 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’s strategies, plans and objectives. However, these words 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;

changes in estimates of proved reserves;

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

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

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

future production and recompletion costs;

the availability of Partnership future cash flows for investor distributions or funding of Well Recompletion Plan activities;

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

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

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

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

the effect of natural gas and oil derivatives activities;

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Index

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 and the Partnership’s other filings with the SEC and public disclosures. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. Other than as required under the securities laws, the Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

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Index

Item 1.

Business

General Information

The Partnership is a publically subscribed West Virginia Limited Partnership which owns an undivided working interest in natural gas and oil wells located in Colorado from which the Partnership produces and sells natural gas and oil. The Partnership was organized and began operations in 2003 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”). The Investor Partners own 80% of the Partnership’s capital, or equity interests. PDC, the Managing General Partner, a Nevada Corporation, owns the remaining 20% of the Partnership’s capital, or equity interest. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner that governs the drilling and operational aspects of the Partnership. The Partnership expended substantially all of the capital raised in the offering for the initial drilling and completion of the Partnership’s wells.

In accordance with the Limited Partnership Agreement (the “Agreement”), general partnership interests were converted to limited partnership units at the completion of the Partnership’s drilling activities. A limited partner’s obligation to the Partnership under West Virginia law is limited to his or her capital contribution.

The following table presents Partnership formation and organizational information through the completion of the drilling phase on January 13, 2004:

				Number of Partner Units
PDC 2003-A Limited Partnership Information	Date	Number of Partners		Additional General Partner Units			Limited Partner Units		Equity Percentage			Amount (millions)

West Virginia Limited Partnership Formation	June 3, 2002
Limited Partnership Termination Date	December 31, 2050

Public Sale of Securities and Funding	April 30, 2003
Investor Partners (1) Unit Cost: $20,000			446		415.15			9.00		80.00	%	$	8.5
PDC, Managing General Partner										20.00	%		1.8
Total funding													10.3
Syndication costs paid to third-party brokers													(0.9	)
Management Fee Paid to PDC													(0.2	)
Net funding available for drilling activities										100.00	%	$	9.2

Conversion of additional General Partners to Limited Partners	January 13, 2004				(415.15	)		415.15
Limited Partnership Units after Conversion					-			424.15

(1)

The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner’s limited partner unit repurchase program as well as the current number of Investor Partners as of the date of filing, see Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. For information concerning the Managing General Partner’s ownership interests in the Partnership as of the date of filing, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The Partnership expects continuing operations of its natural gas and oil properties until such time the Partnership’s wells are depleted or becomes uneconomical to produce, at which time that well may be sold or plugged, reclaimed and abandoned. The Partnership’s maximum term of existence extends through December 31, 2050, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

The address and telephone number of the Partnership and PDC’s principal executive offices, are 1775 Sherman Street, Suite 3000, Denver, Colorado 80203 and (303) 860-5800.

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisition, within the next three years beginning in the fall of 2010, of the remaining third-party Investor Partner interests in the limited partnerships which PDC has sponsored, including PDC 2003-A Limited Partnership. (For additional information regarding PDC’s intention to pursue acquisition of PDC sponsored partnerships, refer to Regulation FD disclosure included in Items 2.02 and/or 7.01 of PDC’s Form 8-Ks dated March 4, 2010, June 9, 2010 and July 15, 2010, which information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report.) Under the Acquisition Plan, any offer will be subject to the terms and conditions of a to be proposed merger agreement wherein the Partnership will merge into PDC. The transaction will also be subject to PDC having sufficient available capital and the approval by a majority of the Investor Partners’ interests, excluding partnership interest owned by PDC, of each respective limited partnership. Should a purchase offer from PDC be proposed, approved by a majority of the Partnerships’ unaffiliated limited partners and consummated, the purchase transaction would result in a liquidating cash distribution to all partners and termination of the existence of the Partnership. There is no assurance that any such acquisition will occur.

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Index

Business Strategy

The primary objective of the Partnership is the profitable operation of developed Colorado natural gas and oil properties and the appropriate allocation of cash proceeds, costs and tax benefits, based on the terms of the Agreement, among Partnership investors. The Partnership operates in one business segment, natural gas and oil sales.

Initial Development

The Partnership’s Denver-Julesburg (“DJ”) Basin wells are situated in the Wattenberg Field, located north and east of Denver, Colorado. The Codell formation, from which natural gas and oil is produced, is the primary producing zone for most of the Partnership’s 22 wells developed in the Wattenberg Field. The Partnership’s Piceance Basin wells are situated in the Grand Valley Field, located near the western border of Colorado. The Mesa Verde formation, where natural gas is the predominant hydrocarbon produced, is the primary producing zone for the Partnership’s three Grand Valley Field wells. The typical well production profile for wells in both the Wattenberg and Grand Valley fields displays an initial high production rate and relatively rapid decline in this production rate in the first few years, followed by years of relatively lower declines.

Future Development Opportunities

Well recompletions in the Codell formation of Wattenberg Field wells, which may provide for additional reserve development and natural gas and oil production, generally occur five to ten years after initial well drilling so that well resources are optimally recovered. These well recompletions would generally be expected to occur based on a favorable general economic environment and commodity price outlook. The Managing General Partner has the authority to determine whether to recomplete the individual wells and to determine the timing of any recompletions. The timing of the recompletions can be affected by the desire to optimize the economic return by recompleting the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership. The number and timing of the Partnership’s well recompletions will be subject to Partnership’s cash availability since borrowing is not permitted. The Managing General Partner may retain Partnership distributable cash flows, if needed, so that Partnership operations may fully develop the Partnership's wells; but if full or partial development of the Partnership's wells proves commercially unsuccessful, a reduction in cash distributions may result.

A recompletion consists of a second fracture treatment in the same formation originally fractured in the initial completion. PDC and other producers have found that the recompletions generally increase the production rate and recoverable reserves of the wells. Historically, the production resulting from PDC's Codell recompletions has been above the modeled economics; however, all recompletions have not been economically successful and future recompletions may not be economically successful. The cost of recompleting a well producing from the Codell formation is generally one third of the cost of a new well. If the recompletion work is performed, PDC will charge the Partnership for the direct costs of recompletions, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the operating costs sharing ratios of the Partnership from funds retained by the Managing General Partner from distributable cash flows.

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Index

Well Recompletion Plan

The Managing General Partner has developed the Well Recompletion Plan for the Partnership’s Wattenberg Field wells that were initially completed in the Codell producing formation during the Partnership’s initial development, more fully described above. Under the plan, the Partnership will initiate Codell formation recompletion activities during 2011. In October 2010 the Managing General Partner will begin to withhold funds from distributable cash flows of the Partnership resulting from current production. The funds retained that 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, 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 Partnership distributions. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions will be completed within a five year period. Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion. This Partnership potentially has 22 well recompletion opportunities. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to be between $1.6 million and $2.2 million. 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.

Drilling and Other Development Activities

The Partnership’s properties (the “Properties”) consist of a working interest in the well bore in each well drilled by the Partnership. The Partnership drilled 25 development wells (12.3 net) (the number of gross wells multiplied by the working interest in the wells owned by the Partnership) during drilling operations that began immediately after funding and concluded in October 2003 when the last of the Partnership’s wells were connected to sales and gathering lines. No exploratory drilling activity was conducted on behalf of the Partnership. The 25 wells discussed above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been expended. In accordance with the D&O Agreement, the Partnership paid its proportionate share of the cost of drilling and completing each well as follows:

The leasehold cost of the prospect;

The intangible well costs for each well completed and placed in production; and

The tangible costs of drilling and completing the partnership wells and of gathering pipelines necessary to connect the well to the nearest appropriate sales point or delivery point.

The Partnership’s business plan going forward, including the Well Recompletion Plan, is to produce and sell the natural gas and oil from the Partnership’s wells, and to make distributions to the partners as outlined in the Partnership’s cash distribution policy, discussed in Item 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Partnership cash distributions will be withheld pursuant to the Well Recompletion Plan.

Title to Properties

The Partnership's leases are direct interests in producing acreage. In accordance with the D&O Agreement, the Managing General Partner exercised due care and judgment, which included curative work for any title defect when discovered, to ensure that each Partnership’s well bore working interest assignment, made effective on the date of well spudding, was properly recorded in county land records. The Partnership believes it holds good and defensible title to its developed properties, in accordance with standards generally accepted in the industry, through the record title held in the Partnership’s name, of each Partnership well’s working interest. The Partnership’s properties are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The Managing General Partner is not aware of any additional burdens, liens or encumbrances customary to the industry, if any, which may materially interfere with the commercial use of the properties. Provisions of the Agreement generally relieve PDC from errors in judgment with respect to the waiver of title defects.

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Index

Natural Gas and Oil Reserves

The Partnership’s gas and oil reserves are located in the United States. The Partnership’s 2009 and 2008 reserve estimates were prepared with respect to reserve categorization, using the definitions then in effect during each year, for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a), as subsequently interpreted by the SEC’s staff interpretations and guidance. The SEC’s Modernization of Oil and Gas Reporting final rule, adopted by the Partnership as of December 31, 2009, prohibited retroactive application of the new oil and gas industry disclosure standards during earlier reporting years. The Managing General Partner established a comprehensive process that governs the determination and reporting of the Partnership’s proved reserves. As part of the Managing General Partner’s internal control process, the Partnership’s reserves are reviewed annually by a team composed of PDC reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data as well as production performance data. The review includes, but is not limited to, confirmation that reserve estimates (1) include all properties owned; (2) are based on proper working and net revenue interests; and (3) reflect reasonable cost estimates and field performance. The internal team compiles the reviewed data and forwards the data to an independent consulting firm engaged to estimate the Partnership’s reserves.

The Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. (Ryder Scott), to estimate the Partnership’s 2009 and 2008 natural gas and oil reserves. When preparing the Partnership's reserve estimates, the independent engineer did not independently verify the accuracy and completeness of information and data furnished by the Managing General Partner with respect to ownership interests, natural gas and oil production, well test data, historical costs of operations and development, product prices, or agreements relating to current and future operations of properties and sales of production. The independent petroleum engineer prepared an estimate of the Partnership’s reserves in conjunction with an ongoing review by the Managing General Partner’s engineers. A final comparison of data was performed to assure that the reserve estimates were complete and reasonable. The final independent petroleum engineer's estimated reserve report was reviewed and approved by the Managing General Partner’s engineering staff and management.

The professional qualifications of the Managing General Partner’s lead engineer primarily responsible for overseeing the preparation of the Partnership’s reserve estimate meets the standards of Reserves Estimator as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This Managing General Partner employee holds a Bachelor of Science degree in Petroleum and Natural Gas Engineering and has over 25 years of experience in reservoir engineering. The individual is a member of the Society of Petroleum Engineers, allowing the individual to remain current with the developments and trends in the industry. Further, during 2009, this individual attended ten hours of formalized training relating to the definitions and disclosure guidelines set forth in the SEC's final rule, Modernization of Oil and Gas Reporting.

Proved reserves are those quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. These reserve quantities are projected to be producible prior to the operating contract’s expiration date, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. The Partnership’s net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. The Partnership’s two categories of proved reserves are as follows:

Proved developed reserves are those natural gas and oil quantities expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for recompletion.

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Index

The table below presents information as of December 31, 2009 and 2008, regarding the Partnership’s proved reserves by production field, as estimated by Ryder Scott and reviewed and approved by the Managing General Partner. Reserves cannot be measured exactly, because reserve estimates involve judgment. The estimates are reviewed periodically and adjusted to reflect additional information gained from reservoir performance data, new geological and geophysical data and economic changes. The Partnership’s estimated proved undeveloped reserves consist entirely of reserves attributable to the future recompletions of the Codell formation in the Wattenberg Field wells. (See Item 1, Business−Business Strategy, Well Recompletion Plan on page 3) For additional information regarding the Partnership’s natural gas and oil reserves see the Supplemental Natural Gas and Oil Information – Unaudited, Net Proved Natural Gas and Oil Reserves that accompanies the financial statements included in this Annual Report. There were no proved undeveloped reserves developed in 2008 or 2009. The changes in these reserves were due to the changes in prices used to value reserves.

	As of December 31, 2009									As of December 31, 2008
					Natural Gas									Natural Gas
	Oil		Natural Gas		Equivalent					Oil		Natural Gas		Equivalent
	(MBbl)		(MMcf)		(MMcfe)		Percent			(MBbl)		(MMcf)		(MMcfe)		Percent
Proved developed
Piceance Basin: Grand Valley Field		3		882		900		70	%		2		901		913		78	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		39		158		392		30	%		23		118		256		22	%
Total proved developed		42		1,040		1,292		100	%		25		1,019		1,169		100	%

Proved undeveloped
Piceance Basin: Grand Valley Field		-		-		-		0	%		-		-		-		0	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		104		542		1,166		100	%		124		821		1,565		100	%
Total proved undeveloped		104		542		1,166		100	%		124		821		1,565		100	%

Proved reserves
Piceance Basin: Grand Valley Field		3		882		900		37	%		2		901		913		33	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		143		700		1,558		63	%		147		939		1,821		67	%
Total proved reserves		146		1,582		2,458		100	%		149		1,840		2,734		100	%

In 2009, the SEC published its final rule regarding the modernization of natural gas and oil reporting, which changed the December 31, 2009 valuation price for in-ground natural gas and oil resources, used to determine economically producible natural gas and oil reserve quantities, from the year-end single-day pricing method that was used to value the Partnership’s reserves at December 31, 2008 and earlier, to a method which applies the 12-month average of the first-day-of-the-month price during each month of 2009. An economically producible quantity is one where the revenue provided by its sale is reasonably likely to exceed the cost to deliver that quantity to market. For more information regarding the SEC’s Modernization of Oil and Gas Reporting adopted by the Partnership at December 31, 2009, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Critical Accounting Policies and Estimates: Recent Accounting Standards.

Operations

General. When Partnership wells were "completed" (i.e., drilled, fractured or stimulated, and all surface production equipment and pipeline facilities necessary to produce the well were installed) production operations commenced on each well. All Partnership wells are complete, and production operations are currently being conducted with regard to each of the Partnership’s productive wells.

PDC, in accordance with the D&O Agreement, is the named operator of record of the Partnership’s wells and may, in certain circumstances, provide equipment and supplies, perform salt water disposal services and other services for the Partnership. Generally, equipment and services are sold to the Partnership at the lower of cost or competitive prices in the area of operations. The Partnership's share of production revenue from a given well is burdened by and subject to, royalties and overriding royalties, monthly operating charges, taxes and other operating costs. It is PDC's practice to deduct operating expenses from the production revenue for the corresponding period. In instances when distributable cash flows are insufficient to make full payment, PDC defers the collection of operating expenses until such time as scheduled expenses may be offset against future Partnership distributable cash flows. In such instances, the Partnership records a liability to PDC.

The Partnership’s operations are concentrated in the Rocky Mountain Region where weather conditions and time periods reserved by leasehold restrictions can exist and limit operational capabilities for as long as six months. Operational constraint challenges such as surface equipment freezing can limit production volumes. Increased competition for oil field equipment, services, supplies and qualified personnel and wildlife habitat protection periods may also adversely affect profitability and reduce cash distributions to the Investor Partners.

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Index

The following table presents the Partnership’s productive wells by operating field as of December 31, 2009 and 2008. Productive wells consist of producing wells and wells capable of producing natural gas and oil in commercial quantities.

	Producing Gas Wells
	2009				2008

Location	Gross		Net		Gross		Net
State of Colorado
Piceance Basin: Grand Valley Field		3.0		1.4		3.0		1.4
Denver-Julesburg (DJ) Basin: Wattenberg Field		20.0		9.9		21.0		10.4
Total Colorado		23.0		11.3		24.0		11.8

Total Productive Wells (1)		23.0		11.3		24.0		11.8

(1) Not included in the producing well statistics above are two Wattenberg Field Partnership wells temporarily not in production at December 31, 2009, which include one well (0.5 net) due to operational issues and one well (0.5 net) due to equipment problems, while one (0.5 net) Wattenberg Field well was temporarily not in production at December 31, 2008 due to equipment problems.

The Partnership’s operating areas are profiled as follows:

DJ Basin, Wattenberg Field, Weld County, Colorado. Located north and east of Denver, Colorado, the Partnership’s wells in this field exhibit production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. Although natural gas is the primary hydrocarbon produced, many wells also produce oil. The Partnership’s development wells in this area are generally 7,000 to 8,000 feet in depth. The primary producing zone for the Partnership’s wells is the Codell formation with two wells also completed in the shallower Niobrara formation. Well spacing ranges from 20 to 40 acres per well.

Piceance Basin, Grand Valley Field, Garfield County, Colorado. Located near the western border of Colorado, the Partnership’s wells in this field have also exhibited production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. These wells generally produce natural gas along with small quantities of oil. The majority of the Partnership’s development wells drilled in the area were drilled directionally from multi-well pads ranging from two to eight or more wells per drilling pad. The primary drilling targets were multiple sandstone reservoirs in the Mesa Verde formation and well depth ranges from 7,000 to 9,500 feet. Well spacing is approximately 10 acres per well.

Sale of Production. In accordance with the D&O Agreement, PDC markets the natural gas produced from the Partnership’s wells primarily to commercial end users, interstate or intrastate pipelines or local utilities on a competitive basis, under the available terms and prices, generally under contracts with indexed monthly pricing provisions. PDC does not charge an additional fee for the marketing of the natural gas and oil because these services are covered by the monthly well operating charge. This monthly charge is more fully described in the following Item 1, Business−Reliance on the Managing General Partner, Provisions of the D&O Agreement. The Managing General Partner believes these contract pricing provisions are customary for the industry. The sales price for natural gas may include revenue from the recovery of propane and butane in the gas stream, as well as a premium for the typical high-energy content of the natural gas. The Partnership’s Wattenberg Field and, to a lesser extent, the Grand Valley Field wells also produce oil in addition to natural gas. The Managing General Partner is currently able to sell, at or near the Partnership’s wells, all of the Partnership’s oil production under a purchase contract with a regional petroleum refiner containing monthly pricing provisions. The Partnership does not refine any of its oil production.

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Index

Natural Gas and Oil Production, Unit Prices and Costs

The following table presents information regarding the Partnership’s operations by field:

	Year Ended December 31,
	2009		2008
Production (1)

Natural gas (Mcf)
Piceance Basin: Grand Valley Field		89,937		84,729
Denver-Julesberg (DJ) Basin: Wattenberg Field		20,264		22,937
Total Natural Gas		110,201		107,666

Oil (Bbls)
Piceance Basin: Grand Valley Field		374		327
Denver-Julesberg (DJ) Basin: Wattenberg Field		5,793		5,236
Total Oil		6,167		5,563

Natural gas equivalent (Mcfe)
Piceance Basin: Grand Valley Field		92,181		86,691
Denver-Julesberg (DJ) Basin: Wattenberg Field		55,022		54,353
Total natural gas equivalent		147,203		141,044

Natural Gas and Oil Sales

Natural gas sales
Piceance Basin: Grand Valley Field	$	233,116	$	520,457
Denver-Julesberg (DJ) Basin: Wattenberg Field		83,093		189,001
Total natural gas sales		316,209		709,458

Oil sales
Piceance Basin: Grand Valley Field	$	16,906	$	30,967
Denver-Julesberg (DJ) Basin: Wattenberg Field		321,110		471,817
Total oil sales		338,016		502,784

Natural gas and oil sales
Piceance Basin: Grand Valley Field	$	250,022	$	551,424
Denver-Julesberg (DJ) Basin: Wattenberg Field		404,203		660,818
Total natural gas and oil sales	$	654,225	$	1,212,242

Average Sales Price (excluding realized gain (loss) on derivatives)

Natural gas (per Mcf)
Piceance Basin: Grand Valley Field	$	2.59	$	6.14
Denver-Julesberg (DJ) Basin: Wattenberg Field		4.10		8.24
Average sales price natural gas, all fields		2.87		6.59

Oil (per Bbl)
Piceance Basin: Grand Valley Field	$	45.20	$	94.70
Denver-Julesberg (DJ) Basin: Wattenberg Field		55.43		90.11
Average sales price oil, all fields		54.81		90.38

Natural gas equivalent (per Mcfe)
Piceance Basin: Grand Valley Field	$	2.71	$	6.36
Denver-Julesberg (DJ) Basin: Wattenberg Field		7.35		12.16
Average sales price natural gas equivalents, all fields		4.44		8.59

Average Production (Lifting) Cost (2) (per Mcfe)

Piceance Basin: Grand Valley Field	$	1.33	$	3.11
Denver-Julesberg (DJ) Basin: Wattenberg Field		2.07		2.00
Average production cost, all fields		1.61		2.68

(1)

Production as shown in the table 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)

Average production unit costs presented exclude the effects of ad valorem and severance taxes.

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Definitions used throughout Item 1, Business:

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

MBbl – One thousand barrels

Mcf – One thousand cubic feet

Mcfe – One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflect the relative energy content

MMcf – One million cubic feet

MMcfe – One million cubic feet of natural gas equivalents

For more information concerning the Partnership’s 2009 and 2008 production volumes and costs, which include severance and ad valorem taxes as reflected in the Partnership’s statements of operations accompanying this report, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report.

Commodity Price Risk Management. The Partnership’s production sold in the spot market and under market index contracts is subject to market price fluctuations. PDC, as Managing General Partner on behalf of the Partnership through the D&O Agreement, uses derivative instruments for a portion of the Partnership’s committed and anticipated natural gas and oil sales to achieve a more predictable cash flow and to reduce exposure to fluctuations in natural gas and oil commodity prices. Since the Partnership manages price risk on only a portion of its future estimated production, future production not covered by derivatives is subject to the full fluctuation of market pricing. The Partnership's policies prohibit the use of derivative financial instruments for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. For more information on the Partnership’s derivative financial instruments, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Commodity Price Risk Management, Net and Liquidity and Capital Resources.

Derivative financial instruments employed for risk management generally consist of “collars,” “swaps” and “basis swaps” on the possible range of prices realized for the sale of natural gas and oil and are New York Mercantile Exchange, or NYMEX-traded and Colorado Interstate Gas Index, or CIG, based contracts for Colorado natural gas and oil production. PDC, as Managing General Partner of the Partnership, enters into derivative transactions on behalf of the Partnership in the same manner in which it enters into transactions for itself.

Collars contain a fixed floor price (put) and ceiling price (call). If the index 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 index price from the counterparty. If the index 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 index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty.

Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the index price and the fixed contract price from the counterparty. If the index 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 index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty.

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. If the index price and contract price are the same, no payment is due to or from the counterparty.

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Historically, the Partnership participated on a pro-rata basis, in all derivative transactions entered into by the Managing General Partner in a given area. The Partnership’s allocation of derivative positions was based on the Partnership’s percentage of estimated production to total estimated production from a given area on a monthly basis. The transactions were on a production month basis. Prior to September 30, 2008, as estimated future production volumes increased due to continued drilling and wells placed into production, the allocation of derivative positions between PDC’s corporate interests and the Partnership, changed on a pro-rata basis. Effective September 30, 2008, PDC changed the allocations procedure whereby the allocation of derivative positions at that date between PDC and each partnership was set at a fixed quantity. For positions entered into subsequent to September 30, 2008, specific designations of the quantities between the Managing General Partner’s corporate interests and each sponsored drilling partnership, including this Partnership, were allocated and fixed at the time the positions were entered into based on estimated future production levels and other factors. Therefore, the Managing General Partner and the sponsored drilling Partnership may not participate on a pro-rata basis or at all in derivative transactions initiated by the Managing General Partner.

All derivative assets and liabilities are recorded on the balance sheets at fair value. PDC, as Managing General Partner, has elected not to formally designate any of the Partnership’s derivative instruments as hedging instruments and therefore, the Partnership does not use hedge accounting. Accordingly, the Partnership is required to recognize changes in the fair value of the Partnership’s derivative instruments in earnings each reporting period and therefore, has the potential for significant earnings volatility. Changes in the fair value of derivative instruments related to the Partnership’s natural gas and oil sales are recorded in the line caption “Commodity price risk management, net” in the Partnership’s statements of operations. For more information regarding the Partnership’s derivative financial instruments and their accounting, see Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments to the Partnership’s accompanying financial statements included in this report.

Delivery Commitments

On behalf of the Partnership, other sponsored drilling program partnerships and for its own corporate account, PDC has entered into third-party sales and processing agreements that generally contain indexed monthly pricing provisions. Although the Partnership is not committed to deliver any fixed and determinable quantities of natural gas or oil under the terms of these agreements, the dedication of the Partnership’s future production is as follows:

Wattenberg Field contractual natural gas processing and sales dedications are multi-year and extend throughout the well’s economic life.

Grand Valley Field contractual natural gas processing and firm sales dedications extend through 2022 and contract provides the seller’s right to convert to a gathering and gas processing contract, solely.

Oil sales dedication is made under a 2-year master agreement with negotiated extensions.

Delivery to Market

The Partnership relies on PDC owned or third-party gathering and transmission pipelines to transport natural gas production volumes to customers. In general, the Partnership has been, and expects to continue to be able to, produce and sell natural gas from Partnership wells without significant curtailment. The Partnership does experience limited curtailments from time to time due to pipeline maintenance and operating issues of the pipeline operators. The Partnership experienced an approximate 10% to 15% curtailment of production volumes in the Piceance Basin due to limited compression and pipeline capacity throughout most of the fourth quarter in 2008. This interruption, due to third party infrastructure, was remediated in early 2009.

Seasonal curtailment typically occurs during July and August as a result of high atmospheric temperatures which reduce compressor efficiency. This reduction in production typically amounts to less than five percent of normal monthly production. The cost, timing and availability of gathering pipeline connections and service varies from area to area, well to well, and over time. Although the Rockies Region has experienced a natural gas transport capacity shortage in the past several years, several key projects placed in-service during the past two years, including the completion of the 1,679-mile Rockies Express Pipeline which extends from Colorado to eastern Ohio and White River Header Pipeline Project in Colorado, have significantly increased natural gas deliverability to intra-regional urban areas as well as inter-regionally, especially to markets in the North Central and Northeastern U.S. as well as Southern California. Transmission capacity is expected to increase in the future based on projects scheduled before various regulatory agencies, but may be delayed due to the recent economic downturn which has weakened U.S. natural gas and oil demand and disrupted global credit markets, which third-party entities access for pipeline expansion financing.

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The Partnership oil production is stored in tanks at or near the location of the Partnership’s wells for routine pickup by oil transport trucks for direct delivery to regional refineries or oil pipeline interconnects for redelivery to those refineries. The cost of trucking or transporting the oil to market affects the price the Partnership ultimately receives for the oil.

Competitive Market Position

Competition is high among persons and companies involved in the exploration and production of natural gas and oil. Because there are thousands of natural gas and oil companies in the United States, the national supply of natural gas, including the Rockies Region which currently supplies approximately 22% of the U.S. natural gas production annually, is diversified. The Partnership believes that the drilling and production capabilities and the experience of the Managing General Partner’s management and professional staff generally enables the Partnership to compete effectively. During the three years preceding 2008, the industry generally experienced increasingly stronger demand for drilling services and supplies that resulted in year-to-year operating cost increases. This trend continued through the first three quarters of the 2008. As a result of the well-publicized turmoil in the financial and commodity markets in late 2008, resultant industry slowdown throughout 2009 and the Managing General Partner’s cost reduction initiatives, the Partnership experienced overall reductions in its 2009 natural gas and oil production costs. For more information on natural gas and oil pricing during 2009 and 2008, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Natural Gas and Oil Production Costs. The Partnership believes that it can compete effectively in its area of operations. Nevertheless, the Partnership’s results of operations and distributable cash flows could be materially adversely affected by the uncertainty in ascertaining the ultimate depth and duration of the current economic environment.

As a result of Federal Energy Regulatory Commission, or FERC, and Congressional deregulation of natural gas and oil prices in the past, prices are generally determined by competitive supply-and-demand market forces. The marketing of natural gas and oil produced by the Partnership is affected by a number of factors, some of which are beyond the Partnership's control and the exact effect of which cannot be accurately predicted. These factors include the volume and prices of crude oil imports, the availability and cost of adequate natural gas and oil pipeline and other transportation facilities, the marketing of competitive fuels, such as coal, nuclear and renewable fuel energy and other matters affecting the availability of a ready market, such as fluctuating supply and demand. Among other factors, the supply and demand balance of crude natural gas and oil in world markets combined with supply and demand balance within and across U.S. geographical regions may have caused significant variations in the prices of these traditional hydrocarbon products over recent years.

The Partnership’s fields are crossed by natural gas pipelines belonging to DCP Midstream LP (“DCP”), Williams Production, RMT (“Williams”) and others. These companies have all traditionally purchased substantial portions of their natural gas supply from Colorado producers. The gas is sold at negotiated prices based upon a number of factors, including the quality of the gas, well pressure, estimated remaining reserves, prevailing supply conditions and any applicable price regulations promulgated by the FERC. FERC natural gas pipeline open-access initiatives implemented during the mid-1980’s to mid-1990’s, mandated that interstate gas pipeline companies separate their merchant activities from their transportation activities and thus release, on both a short and a long-term basis, available transmission system capacity. Thus, local distribution companies have taken an increasingly active role in acquiring their own natural gas supplies. Consequently, the Managing General Partner believes interstate transmission pipelines and local distribution companies (utilities) are buying natural gas directly from natural gas producers and marketers, and retail unbundling efforts are causing many end-users to buy their own reserves. In general, the Partnership has been and expects to continue to be able to produce and sell natural gas and oil from the Partnership’s wells at locally competitive prices.

The Partnership’s secondary hydrocarbon product is oil. In contrast to U.S. natural gas pricing, which is determined more directly by North American supply-demand factors with some increasing role played by liquefied natural gas, or LNG, importation, crude oil pricing is subject to global supply-demand influences including the presence of the Organization of Petroleum Exporting Countries, or OPEC, whose members establish prices and production quotas for petroleum products of OPEC members from time to time. The Managing General Partner is unable to predict what effect, if any, future OPEC actions will have on the quantity of, or prices received for, natural gas and oil produced and sold from the Partnership's wells.

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Colorado accounts for approximately 1% of the U.S.’s total annual domestic oil production and this production generally provides feedstock for Colorado’s two refineries located north of Denver and owned by Suncor Energy (USA) Inc. (“Suncor”). Rocky Mountain oil sales have traded at a discount compared to supplies available elsewhere in the U.S. due to an excess supply situation in the region that arose as a result of rising Canadian tar sand imports and lack of inter-regional export oil pipeline capacity to higher-oil demand regions. However, increased refining capacity near Denver has enabled local Colorado oil suppliers, including the Partnership, to receive pricing advantage over supplies located in less densely-populated northern Rocky Region areas.

Reliance on Managing General Partner

General. As provided by the Agreement, PDC, as Managing General Partner, has authority to manage the Partnership’s activities through the D&O Agreement, utilizing its best efforts to carry out the business of the Partnership in a prudent and business-like fashion. PDC has a fiduciary duty to exercise good faith and deal fairly with Investor Partners. PDC’s executive staff manages the affairs of the Partnership, while technical geosciences and petroleum engineering staff oversee the well drilling, completions, recompletions, and operations. PDC’s administrative staff controls the Partnership’s finances and makes distributions, apportions costs and revenues among wells and prepares Partnership reports, financial statements and filings presented to Investor Partners, tax agencies and the SEC, as required.

Provisions of the D&O Agreement. Under the terms of the D&O Agreement, the Partnership has authorized and extended to PDC the authority to manage the production operations of the natural gas and oil wells in which the Partnership owns an interest, including the initial drilling, testing, completion, and equipping of wells; subsequent well recompletion, where economical, and ultimate evaluation for abandonment. Further, while the Partnership has the right to take in-kind and separately dispose of its share of all natural gas and oil produced from the Partnership’s wells. The Partnership designated PDC as its natural gas and oil production marketing agent and authorized PDC to enter into and bind the Partnership, under those agreements PDC deems in the best interest of the Partnership, in the sale of the Partnership’s natural gas and oil. Generally, PDC has limited liability to the Partnership for losses sustained or liabilities incurred, except as may result from the operator's gross or willful negligence or misconduct. PDC may subcontract certain functions as operator for Partnership wells but retains responsibility for work performed by subcontractors. The D&O Agreement remains in force as long as any well or wells produce, or are capable of economic production, and for an additional period of 180 days from cessation of all production or until PDC is replaced as Managing General Partner as provided for in the D&O Agreement.

To the extent the Partnership has less than a 100% working interest in a well, Partnership obligations and liabilities are limited to its proportionate working interest share and thus, the Partnership paid only its proportionate share of total lease and development costs, pays only the Partnership’s proportionate share of operating costs, and receives its proportionate share of production subject only to royalties and overriding royalties.

Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the D&O Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services or other services for the Partnership at the lesser of cost or competitive prices in the area of operations.

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Insurance. The Partnership's production operations involve a variety of operating risks, including but not limited to fire, explosions, blowouts, pipe failure, casing collapse and abnormally pressured formations which could result in injury, loss of life or suspension of operations, and environmental hazards such as natural gas leaks, ruptures and discharges of toxic gas which could result in environmental damage and clean-up obligations. PDC, in its capacity as operator, has purchased various insurance policies, including worker’s compensation, operator's bodily injury liability and property damage liability insurance, employer's liability insurance, automobile public liability insurance and operator's umbrella liability insurance and intends to maintain these policies subject to PDC's analysis of their premium costs, coverage and other factors. During drilling operations, the Managing General Partner maintained public liability insurance of not less than $10 million; however, PDC may at its sole discretion in other situations, increase or decrease policy limits, change types of insurance and name PDC and the Partnership, individually or together, parties to the insurance as deemed appropriate under the circumstances, which may vary materially. As operator of the Partnership's wells, PDC requires its subcontractors to carry liability insurance coverage with respect to the subcontractors’ activities. PDC’s management, in its capacity as Managing General Partner, believes that in accordance with customary industry practice, adequate insurance, including insurance by PDC’s subcontractors, has been provided to the Partnership with coverage sufficient to protect the Investor Partners against the foreseeable risks of operation, drilling, recompletions and reworks and ongoing productions operations. However, there can be no assurance that this insurance will be adequate to cover all losses or exposure for liability and thus, the occurrence of a significant event not fully insured against, could materially adversely affect Partnership operations and financial condition. Furthermore, the Partnership is not insured against economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or the Partnership’s inability to deliver natural gas. As of the date of this filing, the Managing General Partner has no knowledge that such events have occurred.

Customers

PDC markets the natural gas and oil from Partnership wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of the Partnership. Currently, PDC sells Partnership natural gas in the Piceance Basin to Williams Production RMT (“Williams”), which has an extensive gathering and transportation system in this Basin. In the Wattenberg Field, the gas is sold primarily to DCP Midstream LP (“DCP”), which gathers and processes the gas and liquefiable hydrocarbons produced. Natural gas produced in Colorado may be impacted by changes in market prices on a national level, as well as changes in the market for natural gas within the Rocky Mountain Region. Sales of natural gas from the Partnership's wells to DCP and Williams are made on the spot market via open-access transportation arrangements through Williams or other pipelines and may be impacted by capacity interruptions on pipelines transporting natural gas out of the region.

The Partnership’s crude oil production is sold, at or near the Partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry, primarily as feedstock for refineries currently owned by Suncor, which are located north of Denver, Colorado. Oil prices fluctuate not only with the general market for oil as may be indicated by changes in the NYMEX, but also due to changes in light-heavy crude oil supply and product demand-mix applicable to specific refining regions. Through December 31, 2008, PDC sold 100% of the crude oil from the Partnership’s wells to Teppco Crude Oil, LP (“Teppco”). Beginning January 1, 2009, Suncor became the Partnership’s primary oil purchaser.

Industry Regulation

While the prices of natural gas and oil are set by the market, other aspects of the Partnership's business and the industry in general are heavily regulated. The following summary discussion of the regulation of the United States industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Partnership's operations may be subject.

The availability of a ready market for natural gas and oil production depends on several factors beyond the Partnership's control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas and oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of natural gas and oil, to prevent waste of natural gas and oil, to protect rights of owners in a common reservoir and to control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies.

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Legislative proposals and proceedings that might affect the petroleum and natural gas industries occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. These proposals involve, among other things, imposition of direct or indirect price limitations on natural gas production, expansion of drilling opportunities in areas that would compete with Partnership production, imposition of land use controls, landowners' "rights" legislation, alternative fuel use requirements and tax incentives and other measures. The petroleum and natural gas industries historically have been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. The Partnership cannot determine to what extent its future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. Illustrative of this trend are the regulations implemented in 2009 by the State of Colorado, which focus on the natural gas and oil industry. These multi-faceted regulations significantly enhance requirements regarding natural gas and oil permitting, environmental requirements and wildlife protection. Permitting delays and increased costs could result from these final regulations. Other potential or recently enacted laws and regulations affecting the Partnership include the following:

The U.S. Environmental Protection Agency, or EPA, has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities. The EPA has held public meetings around the country on this issue that have been well publicized and well attended. This renewed focus could lead to additional federal and state laws and regulations affecting the Partnership’s well recompletions, fracturing and operations. Additional laws, regulations or other changes could significantly reduce the Partnership’s future Codell formation development opportunities, increase the Partnership’s costs of operations, and reduce the Partnership’s distributable cash flows, in addition to undermining the demand for the natural gas and oil the Partnership produces.

Several bills in Congress, if passed, would establish a "cap and trade" system regarding greenhouse gas emissions. Companies would be assigned emission "allowances" under these bills which would decline each year. In addition, new EPA greenhouse gas monitoring and reporting regulations may affect the Partnership and the third parties that process the Partnership’s natural gas and oil.

New or increased severance taxes have been proposed in several states, which could adversely affect the existing operations in these states and the economic viability of future well recompletions.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was signed into law. The Dodd-Frank Act regulates derivative transactions, including the Partnership’s natural gas and oil hedging swaps. These swaps are broadly defined to include most of the Partnership’s hedging instruments. The law requires the issuance of new regulations and administrative procedures related to derivatives within one year. The effect of such future regulations on the Partnership’s business is currently uncertain. In particular, note the following:

The Dodd-Frank Act may decrease the Managing General Partner’s ability to enter into hedging transactions which would expose the Partnership to additional risks related to commodity price volatility. Commodity price decreases could then have an immediate significant adverse affect on the Partnership’s revenues and impair the Partnership’s ability to have certainty with respect to a portion of the Partnership’s distributable cash flows. A reduction in cash flows may lead to decreased Investor Partner cash distributions or fewer well recompletions and therefore, decreased Partnership’s proved reserves and future production.

ii.

The Managing General Partner expects that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased counterparty costs. The Partnership’s derivative counterparties may be subject to significant new capital, margin and business conduct requirements imposed as a result of the new legislation.

iii.

The Dodd-Frank Act contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While the Partnership may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking proceedings.

iv.

The above factors could also affect the pricing of derivatives and make it more difficult for the Managing General Partner to enter into hedging transactions on behalf of the Partnership, on favorable terms.

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Environmental Regulation

The Partnership’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and tougher environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs and reduced access to the natural gas industry in general, our business and prospects could be adversely affected. In 2009, the State of Colorado’s Oil and Gas Conservation Commission implemented new broad-based environmental and wildlife protection regulations for the industry which are expected to increase the Partnership’s well recompletion costs and ongoing level of natural gas and oil production costs.

Partnership expenses relating to preserving the environment have risen during the period covered by this report (2009-2008) and are expected, as a consequence of the factors described above, to continue to rise in 2010 and beyond. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. While environmental regulations have had no materially adverse effect on the Partnership’s operations to date, no assurance can be given that environmental regulations or interpretations of such regulations will not in the future, result in a curtailment of production or otherwise have a materially adverse effect on Partnership results of operations or distributable cash flows. See Note 9, Commitments and Contingencies, Stormwater Permit.

The Partnership generates wastes that may be subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The U.S. Environmental Protection Agency, or EPA, and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements.

The Partnership’s operations may be subject to the Clean Air Act, or CAA, and comparable state and local requirements. The State of Colorado has implemented new air emission regulations in 2009, which affect the industry, including the Partnership’s operations.

Available Information

The Partnership is subject to the reporting and information requirements of the Securities Exchange Act of 1934, as amended, and is as a result obligated to file periodic reports, proxy statements and other information with the SEC. The SEC maintains a website that contains the annual, quarterly, and current reports, proxy and information statements, and other information regarding the Partnership, which the Partnership electronically files with the SEC. The address of that site is http://www.sec.gov. The Central Index Key, or CIK, for the Partnership is 0001270426. You can read and copy any materials the Partnership files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1850, Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

Number of total and full-time employees

The Partnership has no employees and relies on the Managing General Partner to manage the Partnership’s business. PDC’s officers, directors and employees receive direct remuneration, compensation or reimbursement solely from PDC, and not the Partnership, with respect to their services rendered in their capacity to act on behalf of PDC, as Managing General Partner. See Item 11, Executive Compensation and Item 13, Certain Relationships and Related Transactions, and Director Independence for a discussion of compensation paid by the Partnership to the Managing General Partner.

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Item 1A.

Risk Factors

Not Applicable

Item 1B.

Unresolved Staff Comments

None

Item 2.

Properties

Information regarding the Partnership’s wells, production, proved reserves and acreage are included in Item 1 and Note 2, Summary of Significant Accounting Policies, to the Partnership’s financial statements included in this report.

Item 3.

Legal Proceedings

The Registrant is not currently subject to any material pending legal proceedings.

See Note 9, Commitments and Contingencies to the accompanying financial statements for additional information related to litigation.

Item 4.

[Removed and Reserved]

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PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

At June 30, 2010, the Partnership had 435 Investor Partners holding 424.15 units and one Managing General Partner. The investments held by the Investor Partners are in the form of limited partnership interests. Investor Partners' interests are transferable; however, no assignee of units in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. As of June 30, 2010, the Managing General Partner has repurchased 18.3 units of Partnership interests from Investor Partners.

Market. There is no public market for the Partnership units nor will a public market develop for these units in the future. Investor Partners may not be able to sell their Partnership interests or may only be able to sell their Partnership interest for less than fair market value. No transfer of a unit may be made unless the transferee satisfies relevant suitability requirements, as imposed by federal and state law or the Partnership Agreement. The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with applicable securities laws. A sale or transfer of units by an individual investor partner requires PDC’s, as Managing General Partner, prior written consent. For these and other reasons, an individual investor partner must anticipate that he or she may have to hold his or her partnership interests indefinitely and may not be able to liquidate his or her investment in the Partnership. Consequently, an individual investor partner must be able to bear the economic risk of investing in the Partnership for an indefinite period of time.

Cash Distribution Policy. PDC plans to make distributions of Partnership cash on a monthly basis, but no less often than quarterly, subject to funds being available for distribution. PDC will make cash distributions of 80% of distributable cash to the Investor Partners, including any Investor Partner units purchased by the Managing General Partner, and 20% of distributable cash to the Managing General Partner, throughout the term of the Partnership. Cash is distributed to the Investor Partners and PDC currently as a return of capital in the same proportion as their proportional interest in the net income of the Partnership.

PDC cannot presently predict amounts of future cash distributions, if any, from the Partnership. However, PDC expressly conditions any and all future cash distributions upon the Partnership having sufficient cash available for distribution. Sufficient cash available for distribution is defined generally as cash generated by the Partnership in excess of the amount the Managing General Partner determines is necessary or appropriate to provide for the conduct of the Partnership's business, to comply with applicable law, to comply with any other agreements or to provide for future distributions to unit holders. In this regard, PDC reviews the accounts of the Partnership at least quarterly for the purpose of determining the sufficiency of distributable cash available for distribution. Amounts will be paid to Investor Partners only after payment of fees and expenses to the Managing General Partner and its affiliates and only if there is sufficient cash available.

The ability of the Partnership to make or sustain cash distributions depends upon numerous factors. PDC can give no assurance that any level of cash distributions to the Investor Partners of the Partnership will be attained, that cash distributions will equal or approximate cash distributions made to investor partners of prior drilling programs sponsored by PDC, or that any level of cash distributions can be maintained. Fully developing all of the Partnership’s properties would require substantial capital expenditures. Because of the restrictions set forth in the Agreement on borrowing money and making assessments on limited partnership units, the Partnership would generally be unable to fund such capital expenditures without retaining all or a substantial portion of the Partnership’s cash flow.

Implementation of the Well Recompletion Plan would reduce or eliminate Partnership distributions to investors while the work is being conducted and paid for. Depending upon the level of withholding and the results of operations, it is possible that investors could have taxable income from the Partnership without any corresponding distributions in the future. If PDC were to be successful in the future acquisition effort of this Partnership, liquidation of the Partnership and a final payout would result in cessation of all future cash payments. The exchange by an investor partner of limited partnership units for cash pursuant to any merger would be a taxable transaction for U.S. federal income tax purposes. The effects of a potential acquisition may be different for each investor partner. For more information concerning the Partnership’s Well Recompletion Plan see Item 1, Business−Future Development Opportunities and Well Recompletion Plan and additional information regarding PDC’s disclosed partnership acquisition intensions, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−PDC Sponsored Drilling Program Acquisition Plan.

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Index

Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Well Recompletion Plan and any potential merger. The above discussion is not intended as a substitute for careful tax planning, and third-party Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the Well Recompletion Plan and any potential merger.

The following table presents cash distributions made to the Partnership’s investors for the periods described:

	Cash
Period	Distributions

For the year ended December 31, 2009	$	881,248
For the year ended December 31, 2008		976,387

For the period from the Partnership's inception to December 31, 2009	$	8,889,984

The volume and rate of production from producing wells naturally declines with the passage of time and is generally not subject to the control of management. The cash flow generated by the Partnership's activities and the amounts available for distribution to the Partnership's Investor Partners will, therefore, decline in the absence of significant increases in the prices that the Partnership receives for its natural gas and oil production, or significant increases in the production of natural gas and oil from the successful additional development of these properties, if any. The funds necessary for any additional development would be withheld from the Partnership's distributable cash flows. As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners would then decrease. For more information regarding recompletion of the Partnership’s Wattenberg Field wells see Item 1, Business−Business Strategy, Future Development Opportunities on page 4. For more information concerning the Partnership’s cash flows from operations see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Liquidity and Capital Resources.

Unit Repurchase Program. Investor Partners may request that the Managing General Partner repurchase limited partnership units at any time beginning with the third anniversary of the first cash distribution of the Partnership. The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10% of the initial subscriptions if requested by an individual investor partner, subject to PDC’s financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the Partnership to be treated as a “publically traded partnership” or result in the termination of the Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis. In addition to the above repurchase program, 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.

The following table presents information about the Managing General Partner’s limited partner unit repurchases under the unit repurchase program during the periods described below:

Unit repurchase program period (1)	Units Repurchased During Month Ended		Average Price Paid per Unit

May 1−31 2008		1.00	$	4,795
August 1−31, 2008		5.00		5,441
September 1−30, 2008		0.25		6,260

April 1−30 2009		0.25	$	7,260
May 1−31 2009		1.00		7,620

(1)

There were no additional unit repurchase program limited partnership unit repurchases by PDC during the six months ended June 30, 2010.

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Index

Item 6.

Selected Financial Data

Not applicable

Item 7.

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

The following discussion and analysis, as well as other sections in this Form 10-K, should be read in conjunction with the Partnership’s accompanying financial statements and related notes to the financial statements included in this report. Further, the Partnership encourages the reader to revisit the Special Note Regarding Forward-Looking Statements on page 1 of the report.

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisition, within the next three years beginning in the fall of 2010, of the remaining third-party Investor Partner interests in the limited partnerships which PDC has sponsored, including PDC 2003-A Limited Partnership. (For additional information regarding PDC’s intention to pursue acquisition of PDC sponsored partnerships, refer to Regulation FD disclosure included in Items 2.02 and/or 7.01 of PDC’s Form 8-Ks dated March 4, 2010, June 9, 2010 and July 15, 2010, which information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report.) Under the Acquisition Plan, any offer will be subject to the terms and conditions of a to be proposed merger agreement wherein the Partnership will merge into PDC. The transaction will also be subject to PDC having sufficient available capital and the approval by a majority of the Investor Partners’ interests, excluding partnership interest owned by PDC, of each respective limited partnership. Should a purchase offer from PDC be proposed, approved by a majority of the Partnerships’ unaffiliated limited partners, and consummated, the purchase transaction would result in a liquidating cash distribution to all partners and termination of the existence of the Partnership. There is no assurance that any such acquisition will occur.

Partnership Overview

PDC 2003-A Limited Partnership engages in the development, production and sale of natural gas and oil. The Partnership began natural gas and oil operations in April 2003 and currently operates 23 gross (11.3 net) wells located in the state of Colorado. In addition, two Wattenberg Field Partnership wells are temporarily not in production at December 31, 2009: one well (0.5 net) due to operational issues and one well (0.5 net) due to equipment problems. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. PDC, on behalf of the Partnership through the D&O Agreement, may enter into multi-year contracts which generally have monthly index-based pricing provisions, 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 may be affected by demand factors.

Well Recompletion Plan

The Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, the Managing General Partner has developed a Well Recompletion Plan for the Codell formation of the Partnership’s Wattenberg Field wells that may provide for additional reserve development and production. The well recompletions are generally planned to occur five to ten years after initial well drilling so that well resources are optimally recovered and would generally be expected to occur within a favorable general economic environment and commodity price outlook. The Managing General Partner has developed a plan to initiate recompletion activities during 2011. See Item 1, Business−Future Development Opportunities and Well Recompletion Plan for more information about the Codell recompletion and the Managing General Partner plan.

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Index

2009 and 2008 Partnership Overview

The year 2008 was a year of significant events: natural gas and oil prices reached record and near record highs, respectively, through July. Then, in the midst of U.S. credit turmoil and a worldwide economic slump in December 2008, oil prices fell to their lowest in the four year period while natural gas prices decreased approximately 50%. Although natural gas prices rebounded in the last two months of 2009 from earlier in the year, the Partnership overall, experienced substantially lower natural gas and oil commodity pricing in 2009 compared to 2008 as a consequence of the protracted economic recession and ensuing uncertainty in the timing of ongoing economic recovery.

Natural gas and oil sales totaled $0.6 million during 2009 compared to $1.2 million during 2008. This decrease was driven primarily by a depressed commodity price environment that was partially offset by a modest increase in production volumes. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $4.44 for 2009 compared to $8.59 for the previous year, a decline of 48%. The Partnership’s production increased to 147 MMcfe for the 2009 annual period compared to 141 MMcfe for the same 2008 period, a modest increase of 4% due to the improved performance of one Grand Valley Field well that offset natural gas and oil production declines at the Partnership’s remaining wells. Period-to-prior-year period production declines are expected declines that naturally take place over a natural gas and oil well’s production life cycle.

While the significant declines in commodity prices have negatively impacted the Partnership’s results of operations for 2009, the Managing General Partner believes that managing the Partnership’s operations, by partially reducing the negative impacts of lower prices through the Partnership’s derivative positions, was reasonably successful. Realized derivative gains from natural gas and oil sales contributed an additional $2.63 per Mcfe, or $0.4 million, and $0.23 per Mcfe, or $32,000, to 2009 and 2008 total revenues, respectively. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased 20% to $7.07 during 2009 from $8.82 during the prior year. Although the Partnership’s 2009 natural gas and sales revenues declined by 46%, or $0.6 million compared to 2008, the Partnership’s annual cash flows provided by operating activities decreased by $0.1 million, primarily benefited by the previously mentioned Partnership increase in realized derivative gains for the 2009 annual period.

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Index

Results of Operations

Summary Operating Results

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

	Year Ended December 31,
	2009		2008			Change
Number of producing wells (end of period)		23		24			-

Production (1)
Natural gas (Mcf)		110,201		107,666			2	%
Oil (Bbl)		6,167		5,563			11	%
Natural gas equivalents (Mcfe) (2)		147,203		141,044			4	%
Mcfe per day		403		386

Natural Gas and Oil Sales
Natural gas	$	316,209	$	709,458			-55	%
Oil		338,016		502,784			-33	%
Total natural gas and oil sales	$	654,225	$	1,212,242			-46	%

Realized Gain (Loss) on Derivatives, net (3)
Natural gas	$	274,387	$	45,996			*
Oil		111,573		(13,791	)		*
Total realized gain on derivatives, net	$	385,960	$	32,205			*

Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	2.87	$	6.59			-56	%
Oil (per Bbl)		54.81		90.38			-39	%
Natural gas equivalents (per Mcfe)		4.44		8.59			-48	%

Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	5.36	$	7.02			-24	%
Oil (per Bbl)		72.90		87.90			-17	%
Natural gas equivalents (per Mcfe)		7.07		8.82			-20	%

Average Lifting Cost (per Mcfe) (4)	$	1.82	$	3.26			-44	%

Operating costs and expenses:
Direct costs - general and administrative	$	76,747	$	39,331			95	%
Depreciation, depletion and amortization	$	679,761	$	457,783			48	%

Cash distributions	$	881,248	$	976,387			-10	%

* 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 we have an interest by the average 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)

Amounts represent realized derivative gains (losses) related to natural gas and oil sales.

(4)

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

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Index

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, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content

MMcfe – One million cubic feet of natural gas equivalents

MMbtu – One million British Thermal Units

Natural Gas and Oil Sales

The table below shows sales and production information for each quarter for the years ended December 31, 2009 and 2008. Natural gas and oil sales exclude the impact of commodity-based derivatives, which are reflected in the line “Commodity price risk management, net” in the statements of operations. (In thousands except for per Mcf, per Bbl and per Mcfe amounts and percentage changes).

	2009									2008
Total	Sales (in thousands)			MMcfe			per Mcfe			Sales (in thousands)		MMcfe		per Mcfe
Jan-Mar	$	144		$	39		$	3.72		$	354		41	$	8.57
Apr-Jun		156			38			4.07			373		34		11.11
Jul-Sept		168			37			4.58			342		35		9.77
Oct-Dec		186			33			5.57			143		31		4.60
Total	$	654			147		$	4.44		$	1,212		141	$	8.59
Change (year over year)		-46	%		4	%		-48	%

	2009									2008
Natural Gas	Sales (in thousands)			MMcf			per Mcf			Sales (in thousands)		MMcf		per Mcf
Jan-Mar	$	91			30		$	3.04		$	220		31	$	6.95
Apr-Jun		61			28			2.20			225		26		8.70
Jul-Sept		70			27			2.60			180		26		7.03
Oct-Dec		94			25			3.69			84		25		3.44
Total	$	316			110		$	2.87		$	709		108	$	6.59
Change (year over year)		-55	%		2	%		-56	%

	2009									2008
Oil	Sales (in thousands)			MBbl			per Bbl			Sales (in thousands)		MBbl		per Bbl
Jan-Mar	$	55		$	1		$	35.89		$	134		2	$	83.26
Apr-Jun		94			2			54.00			148		1		114.95
Jul-Sept		97			2			61.30			162		2		103.09
Oct-Dec		92			1			69.84			59		1		53.61
Total	$	338			6		$	54.81		$	503		6	$	90.38
Change (year over year)		-33	%		11	%		-39	%

Commodity price declines were the primary contributor to the $0.6 million decrease in natural gas and oil sales in 2009 compared to the prior year. The 46% decrease in total sales in 2009 as compared to 2008 was due to a significantly lower average sales price per Mcfe, of 48%, partially offset by a modest increase in production volumes, on a Mcfe or energy equivalency basis, of 4%. The decrease in natural gas revenues of 55% contrasts to the more moderate reduction in oil revenues of 33% which reflects the less significant reduction in average oil sales prices per Bbl, of 39%, as compared to the reduction in natural gas sales prices per Mcf, of 56%, during the period.

On a quarterly basis, total sales for each of the first three quarters in 2009 as compared to the same periods in 2008, decreased by $0.2 million, respectively, due primarily to commodity price declines that were a result of the 2009 economic recession’s downward pressure on demand for natural gas and oil commodities and resulting prices compared to the robust energy commodity price environment before the late-2008 global financial crisis and significant decline in commodity prices. Fourth quarter 2009 total sales remained substantially unchanged from the prior-year comparable period due to the effect of stronger 2009 late-fall natural gas pricing than that of the 2008 global financial crisis period. Although normal quarter-to-prior year quarter production declines are expected, slightly higher second, third and fourth quarter 2009 natural gas production volumes were benefitted by one Grand Valley Field’s well’s performance improvement, which offset expected normal production decreases in the Partnership’s remaining wells, compared to well production during prior year quarters.

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Index

Natural Gas and Oil Pricing

Financial results depend upon many factors, particularly the price of natural gas and oil and on PDC’s ability to market the Partnership’s production effectively. Natural gas and oil prices are among the most volatile of all commodity prices. This price volatility has a material impact on the Partnership’s financial results. Natural gas and oil prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality and availability of sufficient pipeline capacity. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets has resulted in a local market oversupply situation from time to time.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a variety of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby regional prices.

The CIG Index, and other indices for natural gas 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 NYMEX based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets. This “negative differential” has narrowed in the last year and is lower than historical variances.

Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct transmission facilities to increase pipeline capacity to Northeastern U.S and California markets, rendering the timing, cost and availability of these facilities beyond the Partnership’s control. In view of the regional transportation capacity issues cited herein regarding Rocky Mountain regional production, the Partnership believes that pipeline capacity constraints, although significantly moderated, will continue into the immediate future and that the sale of production in the Rocky Mountain Region will continue to be influenced by price and subject to the previously noted, “negative differential.” To that end, the Partnership has been able to sell all of its production to date, has not had to significantly curtail its production for long periods of time because of an inability to sell its production because of pipeline deliverability constraints and believes that it will be able to sell all of its future production at market prices.

Commodity Price Risk Management, Net

Natural Gas and Oil Sales Derivative Instruments. The Managing General Partner on behalf of the Partnership in accordance with the D&O Agreement, is authorized to utilize various derivative instruments to manage volatility in natural gas and oil prices. The Partnership has in place, a series of collars, fixed-price swaps and basis swaps on a portion of the Partnership’s natural gas and oil production. Under the Partnership’s collar arrangements, should the applicable index rise above the ceiling price, the Managing General Partner pays the difference between the index and the ceiling price to the counterparty; however, should the index drop below the floor price, the counterparty pays the difference between the floor price and the index price to the Managing General Partner. Under the Partnership’s commodity swap arrangements, should the applicable index rise above the swap price, the Managing General Partner pays the difference between the index price and the swap price to the counterparty; however, should the index drop below the swap price, the counterparty pays the difference between the swap price and the index price to the Managing General Partner. Under the Partnership’s basis protection swaps, should the differential widen beyond the swap price, then the counterparty pays the difference between the index price and the swap price to the Managing General Partner; however, should the differential narrow below the swap price, the Managing General Partner pays the difference between the swap price and the index price to the counterparty. See Item 1, Business−Operations – Commodity Price Risk Management for a detailed description of payments under these arrangements. Because the Partnership sells all of its physical natural gas and oil at similar prices to the indexes inherent in the Partnership’s derivative instruments, the Partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the Partnership’s commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps.

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Index

The following table presents the Partnership’s realized and unrealized derivative gains and losses included in commodity price risk management (loss) gain, net for each of the quarterly and annual periods identified.

	Three months ended												Year ended
	March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009			December 31, 2009
Commodity price risk management, net
Realized gains
Oil	$	45,563		$	30,020		$	21,876		$	14,114		$	111,573
Natural Gas		92,658			62,135			56,107			63,487			274,387
Total realized gain, net		138,221			92,155			77,983			77,601			385,960

Unrealized gains (losses)
Reclassification of realized gains included in prior periods unrealized (1)		(115,421	)		(101,810	)		(77,521	)		(75,394	)		(345,147	)
Unrealized (loss) gain for the period (1)		(26,808	)		(137,976	)		(86,648	)		20,638			(255,793	)
Total unrealized loss, net		(142,229	)		(239,786	)		(164,169	)		(54,756	)		(600,940	)
Commodity price risk management (loss) gain, net	$	(4,008	)	$	(147,631	)	$	(86,186	)	$	22,845		$	(214,980	)


	Three months ended												Year ended
	March 31, 2008			June 30, 2008			September 30, 2008			December 31, 2008			December 31, 2008
Commodity price risk management, net
Realized gains (losses)
Oil	$	(8,232	)	$	(23,783	)	$	(14,624	)	$	32,848		$	(13,791	)
Natural Gas		(6,021	)		(46,020	)		19,947			78,090			45,996
Total realized (loss) gain, net		(14,253	)		(69,803	)		5,323			110,938			32,205

Unrealized gains (losses)
Reclassification of realized (gains) losses included in rior periods unrealized (1)		(19,927	)		66,483			135,095			(57,930	)		40,026
Unrealized (loss) gain for the period (1)		(208,396	)		(598,126	)		778,480			408,935			464,588
Total unrealized (loss) gain, net		(228,323	)		(531,643	)		913,575			351,005			504,614
Commodity price risk management (loss) gain, net	$	(242,576	)	$	(601,446	)	$	918,898		$	461,943		$	536,819

(1)

Quarterly amounts presented on the line captioned “Unrealized (loss) gain for the period,” may be reclassified in subsequent quarterly periods, to amounts presented on the line captioned “Reclassification of realized (gains) losses included in prior periods unrealized.” For the years 2009 and 2008, quarterly amounts reclassified in subsequent quarters were $24,999 and $83,695, respectively.

The $0.4 million realized gain recognized in 2009 is a result of lower natural gas and oil commodity prices at settlement compared to the respective strike price. The Partnership recognized realized gains of $0.1 million for each 2009 quarter, respectively, due to the gradual increase in the CIG-index natural gas prices (per MMbtu) and oil prices on NYMEX (per barrel) that occurred within each quarter of the year. The year 2009’s stable commodity pricing was in stark contrast to the commodity market price volatility experienced during 2008. Rocky Mountain Region natural gas and oil prices increased during the first seven months of 2008, resulting in the Partnership’s $0.1 million June 30, 2008 realized loss on its derivative positions that was offset when commodity prices declined sharply during the last five months of 2008, providing the Partnership’s approximately $0.1 million realized gain on its derivative instruments during the December 31, 2008 quarter and modest gain overall, for the year ended 2008.

During 2009, the Partnership recorded current period unrealized derivative losses for the year of approximately $0.2 million, primarily due to the second quarter $0.1 million decrease in fair value of the Partnership’s commodity derivatives resulting from rising forward strip natural gas and oil commodity prices in relation to the Partnership’s derivative contract prices and the third quarter $0.1 million decrease in fair value of the Partnership’s CIG basis protection swaps, resulting from the narrowing of the forward basis differential between NYMEX and CIG indices, in relation to the Partnership’s contract price.

During 2008, the Partnership recorded current period unrealized derivative gains of $0.4 million, primarily related to the Partnership’s natural gas and oil positions which increased in value when the forward prices for natural gas and oil declined substantially in late 2008, relative to the Partnership’s derivative instrument contract prices. The Partnership recognized current period unrealized derivative losses of $0.2 million and $0.6 million, respectively, during the first two quarters of 2008 and unrealized derivative gains of $0.8 million and $0.4 million, respectively, during the remaining two 2008 quarters, as a result of changes in the fair value of the Partnership’s natural gas and oil derivative instruments. As noted earlier, rising Rocky Mountain Region forward strip commodity pricing early in 2008 prior to the global financial crisis, resulted in the Partnership’s quarterly unrealized losses while the steep commodity pricing declines during August through December 2008, resulted in the Partnership’s third and fourth quarter unrealized gains.

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Index

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

The following table presents the Partnership’s derivative positions in effect as of June 30, 2010.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/	Quantity (Gas-		Weighted Average Contract Price				Quantity (Gas-Mmbtu Oil-		Weighted Average Contract		Quantity (Gas-		Weighted Average Contract			Fair Value at June 30,
Index	Mmbtu)		Floors		Ceilings		Bbls)		Price		Mmbtu)		Price			2010(1)

Natural Gas
CIG
10/01 - 12/31/2010		5,276	$	4.75	$	9.45		-	$	-		-	$	-		$	3,220
01/01 - 03/31/2011		7,914		4.75		9.45		-		-		-		-			3,944

NYMEX
07/01 - 09/30/2010		-		-		-		16,776		5.56		17,558		(1.88	)		(5,295	)
10/01 - 12/31/2010		1,670		5.75		8.30		10,071		6.13		12,028		(1.88	)		(448	)
01/01 - 03/31/2011		2,275		5.75		8.30		6,128		6.83		8,403		(1.88	)		(822	)
04/01 - 06/30/2011		-		-		-		16,354		6.78		16,354		(1.88	)		5,824
07/01 - 12/31/2011		-		-		-		32,114		6.76		32,114		(1.88	)		516
2012-2013		3,626		6.00		8.27		113,415		7.05		117,039		(1.88	)		(4,602	)
Total Natural Gas		20,761						194,858				203,496					2,337

Oil
NYMEX
07/01 - 09/30/2010		-		-		-		896		92.96		-		-			14,818
10/01 - 12/31/2010		-		-		-		896		92.96		-		-			13,622
01/01 - 03/31/2011		-		-		-		447		70.75		-		-			(3,282	)
04/01 - 06/30/2011		-		-		-		456		70.75		-		-			(3,714	)
07/01 - 12/31/2011		-		-		-		939		70.75		-		-			(8,217	)
Total Oil		-						3,634				-					13,227

Total Natural Gas and Oil																$	15,564

(1) As of June 30, 2010, approximately 15% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3). See Note 4, Fair Value Measurements, to the accompanying financial statements included in this report.

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Index

Natural Gas and Oil Production Costs

Natural gas and oil production costs include production taxes and transportation costs which vary with revenues and production, well operating costs charged on a per well basis and other direct costs incurred in the production process. As production declines, fixed costs increase as a percentage of total costs resulting in production costs per unit increases. Typically, as production is expected to continue to decline, production costs per unit can be expected to increase in the future until such time as the Partnership successfully recompletes the Wattenberg Field wells. The following table presents the Partnership’s natural gas and oil production costs recorded during each of the three month periods identified:

	2009						2008
	Prod Costs		Mcfe		per Mcfe		Prod Costs		Mcfe		per Mcfe
Jan-Mar	$	72,744		38,918	$	1.87	$	102,464		41,335	$	2.48
Apr-Jun		69,931		38,247		1.83		90,109		33,598		2.68
Jul-Sep		69,170		36,654		1.89		95,504		35,010		2.73
Oct-Dec		56,013		33,384		1.68		171,204		31,101		5.50
Total	$	267,858		147,203	$	1.82	$	459,281		141,044	$	3.26

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

Natural gas and oil production costs during 2009 were lower by $0.2 million, or 42%, than those of the preceding year primarily due to lower commodity valuations that reduced production taxes and lower lease operating expenses due to lower third-party field services costs. Lowering third party service rates are attributable to declining oil field services demand in this low-commodity price environment, as well as the Managing General Partner’s cost reduction initiatives. Natural gas and oil production costs per Mcfe were $1.82 during the year 2009 compared to $3.26 for the year 2008.

On a quarterly basis, natural gas and oil production costs remained substantially unchanged at $0.1 million during each of the first three quarters in 2009 compared to the respective prior year quarter. Fourth quarter 2009 natural gas and oil production costs declined by approximately $0.1 million from the comparable 2008 quarter, primarily as a result the Managing General Partner’s cost reduction initiatives as well as a downward revision of 2009 production tax adjustment that was applicable to previous quarter’s production.

Quarter-to-current year quarter 2008 natural gas and oil production cost per Mcfe increases during the first three quarters of the year, primarily reflect the Partnership’s higher production tax expenditures due to higher commodity valuations. The fourth quarter 2008 production cost per Mcfe increase is the result of the combined effect of the quarter’s higher lease operating costs because of Grand Valley access road maintenance and remediation at two Grand Valley well locations, which was partially offset by lower production tax expenditures due to significantly lower commodity valuations during the late-2008 global credit crisis period.

Quarter-to-current year quarter 2009 natural gas and oil production cost per Mcfe stabilized during the first three quarters of the year. The fourth quarter 2009 reduction in the natural gas and oil production costs per Mcfe primarily reflects lower lease operating expenses due to lower third-party field services costs, whose lowering rates are attributable to declining oil field services demand in this low-commodity price environment, the Managing General Partner’s cost reduction initiatives and the 2009 production tax adjustment noted above.

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Depreciation, Depletion and Amortization

The following table presents the Partnership’s depreciation, depletion, and amortization (“DD&A”) expense recorded for each of the three month periods identified:

	2009						2008
	DD&A		Mcfe		per Mcfe		DD&A		Mcfe		per Mcfe
Jan-Mar	$	190,659		38,918	$	4.90	$	112,998		41,335	$	2.73
Apr-Jun		195,788		38,247		5.12		93,744		33,598		2.79
Jul-Sep		190,205		36,654		5.19		96,741		35,010		2.76
Oct-Dec		103,109		33,384		3.09		154,300		31,101		4.96
Total	$	679,761		147,203	$	4.62	$	457,783		141,044	$	3.25

Depreciation, depletion and amortization (DD&A) expense results solely from the depreciation, depletion and amortization of well equipment and lease costs. The Partnership’s calculation of DD&A expense is primarily based upon year-end proved developed producing natural gas and oil reserve estimates and associated production volumes. For 2008, the Partnership’s natural gas and oil economically producible reserve quantities were determined by valuing in-ground natural gas and oil resources, at the price of natural gas and oil as of December 31, 2008. In 2009, the SEC published its final rule regarding the modernization of natural gas and oil reporting, which changed the valuation price from a December 31 single-day pricing to a price determined by the 12-month average of the first-day-of-the-month price during each month of 2009. Typically as valuation prices increase, the estimated volumes of natural gas and oil reserves may increase, resulting in a decrease in the rate of DD&A for each Mcfe produced. If valuation prices decrease the estimated volumes of natural gas and oil reserves may also decrease, resulting in an increase in the DD&A rate for each Mcfe produced.

The DD&A expense rate per Mcfe increased to $4.62 for the year ended December 31, 2009, compared to $3.25 during the same period in 2008. The variance in the annual per Mcfe rates for the 2009 period compared to the 2008 period is the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates in addition to the effects of downward revisions in the Partnership’s proved developed producing natural gas and oil reserves at December 31, 2008 compared to December 31, 2007. The Partnership’s downward year-end 2008 proved developed producing reserve revision was the primary contributor to the increased DD&A expense of $0.3 million during the first three quarters of 2009. Fourth quarter 2009 DD&A expense declined approximately $0.1 million compared to fourth quarter 2008, based on an upward natural gas and oil proved developed producing reserves revision from the Partnership’s December 31, 2009 annual reserve report, primarily in the Wattenberg Field. Overall, DD&A expense increased $0.2 million during 2009 compared to the prior year. The Partnership’s 2009 annual production volumes on an Mcfe or energy-equivalency basis, increased marginally by 4%, over 2008 production volumes.

The higher fourth quarter 2008 DD&A expense rate per Mcfe compared to the year’s earlier quarter-periods is due to the utilization of the year-end 2008 report’s lower proved developed producing natural gas and oil reserve volumes compared to year-end 2007 reported reserves that was used in determining DD&A expense in earlier 2008 quarters. The lower fourth quarter 2009 DD&A expense rate per Mcfe compared to 2009’s earlier quarter-periods is due to the fourth quarter’s use of the year-end 2009 report’s higher proved developed producing natural gas and oil reserve volumes, compared to year-end 2008 reserves, as noted above. See Supplemental Natural Gas and Oil Information – Unaudited, Net Proved Natural Gas and Oil Reserves that accompanies the financial statements included in this Annual Report, for additional information regarding the Partnership’s reserves reported as of December 31, 2009 and 2008.

Liquidity and Capital Resources

The Partnership’s primary sources of cash in 2009 were provided by operating activities which include the sale of natural gas and oil production, the net realized gains from the Partnership’s derivative positions and the decrease in “Due from Managing General Partner – Other, Net.” These sources of cash were primarily used to fund the Partnership’s operating cost, general and administrative activities and provide monthly distributions to the Investor Partners and PDC, the Managing General Partner. Fluctuations in the Partnership’s operating cash flow are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas and oil sales and realized derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of June 30, 2010, the Partnership had natural gas and oil derivative positions in place covering 72% of expected natural gas production and 64% of expected oil production for the remainder of 2010, at an average price of $3.97 per Mcf and $92.96 per Bbl, respectively. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.

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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 in the rate of production over the remaining life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas and oil production and, in the absence of significant price increases or 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 and a decline in commodity prices 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 and may substantially reduce or restrict the Partnership’s ability to participate in recompletion activities. Future cash distributions may also be reduced to fund well recompletions in the Codell formation of the Wattenberg Field.

Working Capital

The following table presents the Partnership’s working capital position at the end of the three month period indentified:

	As of
	March 31, 2009		June 30, 2009			September 30, 2009		December 31, 2009

Working capital	$	615,644	$	344,322		$	70,345	$	97,724

	As of
	March 31, 2008		June 30, 2008			September 30, 2008		December 31, 2008

Working capital	$	309,520	$	(49,317	)	$	526,273	$	629,392

Working capital at December 31, 2009 was $0.1 million compared to working capital of $0.6 million at December 31, 2008, a decrease of $0.5 million This decrease was primarily due to the following changes in accounts receivable and payable balances:

Natural gas and oil receivables remained substantially unchanged at $0.1 million as of December 31, 2009 and 2008, respectively.

Realized derivative gains receivables decreased by $0.1 million between December 31, 2009 and December 31, 2008.

Net short-term unrealized derivative gains receivable decreased by $0.3 million between December 31, 2009 and December 31, 2008.

The liability Due to Managing General Partner-other, excluding natural gas and oil sales received from third parties and realized derivative gains, increased by $0.1 million between December 31, 2009 and December 31, 2008.

Amounts Due to (from) the Managing General Partner-other, described above, were impacted by non-recurring items during the period ended September 2009. There was a net reduction of $0.4 million in amounts due from the Managing General Partner, as a $0.5 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 $0.1 million. The net cash impact of these transactions increased distributions by $0.4 million during 2009. For more information on the Colorado Royalty Settlement see Note 9, Commitments and Contingencies to the accompanying audited financial statements.

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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 $26,000 and $37,000 for 2009 and 2008, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in November 2003 and has distributed $8.9 million through December 31, 2009. The table below presents cash distributions to the Partnership’s investors. Managing General Partner distributions include amounts distributed to PDC for its Managing General Partner’s 20% ownership share in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.

	Managing General Partner Distributions		Investor Partners Distributions*		Total Distributions

2009
Jan-Mar	$	46,146	$	184,587	$	230,733
Apr-Jun		57,262		229,046		286,308
Jul-Sep		58,058		232,234		290,292
Oct-Dec		14,783		59,132		73,915
	$	176,249	$	704,999	$	881,248

2008
Jan-Mar	$	35,019	$	140,075	$	175,094
Apr-Jun		55,062		220,250		275,312
Jul-Sep		51,665		206,661		258,326
Oct-Dec		53,531		214,124		267,655
	$	195,277	$	781,110	$	976,387

*The following table presents these equity cash distributions during the three month periods identified, associated to limited partnership units repurchased by PDC:

Three months ended	2009		2008

March 31	$	7,436	$	3,579
June 30		9,732		5,964
September 30		10,040		7,446
December 31		2,557		8,626

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Cash Flows From Operating Activities

The following table presents the operating cash flows for the end of the three month periods identified:

	2009
	Quarter ended		Quarter ended		Quarter ended		Quarter ended
	March 31,		June 30,		September 30,		December 31,

Cash flows from operating activities	$	251,591	$	289,898	$	254,844	$	74,021

				2008
	Quarter ended		Quarter ended		Quarter ended		Quarter ended
	March 31,		June 30,		September 30,		December 31,

Cash flows from operating activities	$	197,042	$	288,116	$	260,692	$	271,103

Net cash provided by operating activities was $0.9 million for 2009 compared to $1.0 million for 2008, a decrease of $0.1 million. The decrease in cash provided by operating activities was due primarily to the following:

A decrease in natural gas and oil sales receipts of $0.7 million, or 50%;

An increase in commodity price risk management realized gains receipts of $0.5 million and a decrease in natural gas and oil production costs of $0.2 million, or 42%; and

A decrease in Due from Managing General Partner-other receipts, excluding natural gas and oil sales receipts and realized derivative gain receipts noted above, of approximately $0.1 million primarily due to the non-recurring third quarter 2009 Managing General Partner’s $0.5 million payment to the Partnership for over-withheld production taxes and accrued interest thereon, related to Partnership production prior to 2007, which was partially offset by the Partnership’s approximately $0.1 million payment to the Managing General Partner for royalty settlement costs. For more information on the Colorado Royalty Settlement see Note 9, Commitments and Contingencies to the accompanying financial statements.

Critical Accounting Policies and Estimates

The Managing General Partner has identified the following policies as critical to business operations and the understanding of the results of the operations of the Partnership. The following is not a comprehensive list of all of the Partnership’s accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States, with no need for management's judgment in their application. There are also areas in which management's judgment in selecting any available alternative would not produce a materially different result. However, certain of the Partnership’s accounting policies are particularly important to the portrayal of the Partnership's financial position and results of operations and the Managing General Partner may use significant judgment in their application; as a result these policies are subject to inherent degree of uncertainty. In applying these policies, the Managing General Partner uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies in the accompanying financial statements. The Partnership's critical accounting policies and estimates are as follows:

Revenue Recognition

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

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

Oil Sales. Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable. The Partnership does not refine any of its oil production. The Partnership’s crude oil production is sold to purchasers at or near the Partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

Fair Value of Financial Instruments

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

Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. Included in Level 1 are the Partnership’s commodity derivative instruments for NYMEX-based fixed price natural gas swaps and collars.

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.

Level 3 – Unobservable inputs for the asset or 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 derivative instruments for CIG-based fixed-price natural gas swaps, oil swaps, natural gas and oil collars, and the Partnership’s natural gas basis protection derivative instruments.

Derivative Financial Instruments. The Managing General Partner measures fair value of the Partnership’s derivatives based upon quoted market prices, where available. The Managing General Partner’s 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 Managing General Partner’s valuation determination also gives consideration to the 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. The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties default, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. The Managing General Partner has determined based on this evaluation, that the impact of counterparty nonperformance on the fair value of the Partnership’s derivative instruments is not material. For the years ended December 31, 2009 and 2008, no valuation allowance was recorded. 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.

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Natural Gas and Oil Properties

The Partnership accounts for its natural gas and oil properties under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing natural gas and oil reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved natural gas and oil reserves.

Annually, the Managing General Partner engages an independent petroleum engineer to prepare a reserve and economic evaluation of the Partnership’s properties on a well-by-well basis as of December 31. The process of estimating and evaluating natural gas and oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the Managing General Partner’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s DD&A expense, a change in the Partnership’s estimated reserves could have an effect on its net income.

Proved developed reserves are those natural gas and oil quantities expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for recompletion.

The Partnership assesses impairment of capitalized costs of proved natural gas and oil properties, 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 prices at which management reasonably estimates commodities to be sold. The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and oil. Downward revisions in estimates of the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and therefore a possible impairment of the Partnership’s natural gas and oil properties. If during the completion of the impairment test, 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, which is predominantly unobservable data or inputs (Level 3) and is measured by the amount by which the net capitalized costs exceed fair value. The Partnership’s estimated production used in the impairment testing is taken from the annual reserve report, which is summarized in the Supplemental Natural Gas and Oil Information–Unaudited, Net Proved Natural Gas and Oil Reserves that accompanies the financial statements included in this Annual Report. Estimated undiscounted future net cash flows are determined using prices from the forward price curve. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and oil reserves.

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies to the accompanying financial statements included in this Annual Report, for recently issued and implemented accounting standards including the SEC’s, Modernization of Oil and Gas Reporting, an effort by the SEC to provide investors with a more meaningful and comprehensive understanding of natural gas and oil reserves, that become effective for the Partnership’s financial statements and related disclosures for the year ending December 31, 2009. Since the SEC’s final rule prohibited retroactive application of the new industry accounting and reporting standards, the Partnership’s financial statements and related industry disclosures contained in this Annual Report for the year ending December 31, 2008, are based on those SEC standards then in effect, during the year 2008 and earlier.

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The most significant provision of the new industry accounting and reporting final rule was the change in the method for determining the December 31, 2009 valuation price for in-ground natural gas and oil resources, used to determine economically producible natural gas and oil reserve quantities. The 2009 year-end valuation price was based on the application of the 12-month average of the first-day-of-the-month natural gas and oil commodity price during each month of 2009 while the 2008 year-end valuation price was based on the single-day natural gas and oil commodity price on December 31, 2008. An economically producible quantity is one where the revenue provided by its sale is reasonably likely to exceed the cost to deliver that quantity to market. The Partnership applied the above changes to the Partnership’s financial statements of and for the year ended December 31, 2009. As a result, the Partnership’s fourth quarter DD&A calculation was based on proved developed producing reserves that were calculated using the new SEC reserve reporting guidelines; whereas, DD&A calculations for the first three quarters of 2009 were based on the prior methodology. The impact of using the 12-month average pricing methodology specified under the new SEC reporting rules resulted in an increase of the Partnership’s fourth quarter DD&A expense of approximately $8,000. For more information regarding the Partnership’s natural gas and oil reserves for 2009 and 2008, see the Supplemental Natural Gas and Oil Information–Unaudited, Net Proved Natural Gas and Oil Reserves that accompanies the financial statements included in this Annual Report.

A second provision of the SEC’s modernized oil and gas industry reporting rules is the revised definition for hydrocarbon resources classified as proved undeveloped reserves, or PUD’s. In order to substantiate natural gas and oil reserve quantities so categorized under the new rules, which may require a relatively major expenditure for their development, the Partnership is now required to have made a final investment decision to develop those additional reserves under a defined plan that is within five years of being initiated.

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. Although the new FASB accounting rule became effective for the Partnership’s quarterly and annual SEC reporting beginning September 30, 2009, for purposes of continuity and reader understanding of this comprehensive Annual Report for the years 2009 and 2008, accounting guidance referred to in footnotes and management’s discussion and analysis generally will utilize the Codification’s topical organization structure. Other than the manner in which accounting guidance is referenced, the Partnership’s adoption of the Codification had no impact on the Partnership’s accompanying financial statements or disclosure requirements.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 8.

Financial Statements and Supplementary Data

The financial statements are attached to this Form 10-K beginning at page F-1.

Supplemental financial information required by this Item can be found in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report.

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Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A(T).

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.

2007 Material Weaknesses

As discussed in the Management’s Report on Internal Control Over Financial Reporting included in the Partnership’s 2007 Annual Report on Form 10-K, the Partnership did not maintain effective internal controls over financial reporting as of December 31, 2007, with respect to the following three areas:

The support for the Partnership’s general ledger depends in part on the effectiveness of controls of the Managing General Partner’s spreadsheets. The overall ineffectiveness of the Managing General Partner's spreadsheet controls could have a material effect on the Partnership’s financial statements. The Partnership did not maintain effective controls to ensure the completeness, accuracy, and validity of key financial statement spreadsheets generated by the Managing General Partner. These spreadsheets are utilized by the Partnership to support significant balance sheet and income statement accounts. This material weakness has been remediated as of December 31, 2008.

The support for the Partnership’s derivative calculations depends in part on the effectiveness of controls of the Managing General Partner’s process. The overall ineffectiveness of the Managing General Partner's derivative controls could have a material effect on the Partnership’s financial statements. The Partnership did not maintain effective controls to ensure that the Managing General Partner had policies and procedures, or personnel with sufficient technical expertise to record derivative activities in accordance with generally accepted accounting principles. This material weakness has been remediated as of December 31, 2008.

For the transactions that are directly related to and processed by the Partnership, 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 been remediated as of December 31, 2009.

(a) Evaluation of Disclosure Controls and Procedures

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

Based upon the evaluation, the Managing General Partner’s Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, 2009.

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(b) Management’s Report on Internal Control Over Financial Reporting

Management of PDC, the Managing General Partner of the Partnership, is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Exchange Act Rules 13a-15(f) and 15d-15(f) as a process designed by, or under the supervision of, the issuer’s principal executive and principal financial officers, or persons performing similar functions, and effected by the issuer’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

(1)

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;

(2)

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and

(3)

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer’s assets that could have a material effect on the financial statements of the issuer.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Management of the Managing General Partner has assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2009, based upon the criteria established in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management of the Managing General Partner concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2009.

The accompanying Annual Report on Form 10-K does 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.

c) Remediation of Material Weaknesses in Internal Control

PDC, the Managing General Partner, with participation from the Audit Committee of its Board of Directors, addressed the material weaknesses disclosed in the Partnership’s 2007 Annual Report on Form 10-K. The Managing General Partner believes that the effective implementation of changes in internal controls over financial reporting during 2008 outlined below, remediated the first two known 2007 material weaknesses identified above, as of December 31, 2008.

The Partnership made the following changes in its internal control over financial reporting of the Partnership (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during 2008.

During the first quarter of 2008, the Managing General Partner implemented the general ledger, accounts receivable, cash receipts, revenue, financial reporting, and joint interest billing modules as part of a new broader financial system. The new financial system enhanced operating efficiencies and provided more effective management of Partnership business operations and processes. The Managing General Partner has taken the necessary steps to monitor and maintain appropriate internal controls during this period of change. These steps include documenting all new business process changes related to the new financial system; testing all new business processes on the new financial system; and conducting training related to the new business processes and to the new financial system software. The Managing General Partner expects the implementation of the new financial system will strengthen the overall systems of internal controls due to enhanced automation and integration of related processes. The Managing General Partner continues to modify the design and documentation of internal control processes and procedures related to the new financial system to supplement and complement existing internal controls over financial reporting. The system changes were developed to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in the Partnership's internal control over financial reporting. Testing of the controls related to this new system was included in the scope of the Managing General Partner's assessment of the Partnership's internal control over financial reporting for 2008.

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During the third quarter of 2008, the Managing General Partner improved controls over certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts. Specifically, the Managing General Partner enhanced the spreadsheet policy to provide additional clarification and guidance with regard to risk assessment and enforced controls over: 1) the security and integrity of the data used in the various spreadsheets, 2) access to the spreadsheets, 3) changes to spreadsheet functionality and the related approval process and 4) increased management’s review of the spreadsheets.

During the third quarter of 2008, in addition to accredited derivative training attended by key personnel, the Managing General Partner created and documented a desktop procedure to: 1) ensure the completeness and accuracy of the Managing General Partner’s derivative activities and 2) supplement key controls previously existing in the process. Further, the desktop procedure provides for a more robust review of the Managing General Partner’s derivative process. This procedure continued to be enhanced throughout the fourth quarter of 2008.

The Managing General Partner believes that the effective implementation of changes in internal controls over financial reporting during 2009 outlined below, remediated the third known 2007 material weakness identified above, as of December 31, 2009.

During the first and second quarters of 2009, the Partnership developed a plan to improve controls over certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts. The Partnership also created and documented a procedural framework to ensure the completeness and accuracy of the Partnership’s derivative activities. Additionally, the Partnership completed the development of a revised financial close and reporting narrative that adequately describes the process, identifies key controls and assesses segregation of duties.

In the third quarter, the Partnership developed documentation that describes the business processes and identifies key controls for internal control over financial reporting that assisted the Managing General Partner in adequately assessing internal control over financial reporting for the Partnership. In addition, the Partnership developed documentation and procedures to adequately assess segregation of duties. The controls and procedures were tested prior to 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.

(d) Other Changes in Internal Control over Financial Reporting

During 2009, PDC made the following changes in PDC’s internal control over financial reporting (as 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 replacing 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 was included in the scope of PDC’s assessment of its internal control over financial reporting as of December 31, 2009.

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PDC, the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting, as previously defined, during the quarters ended March 31 and June 30, 2010, that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

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 weaknesses of the Partnership referenced above may be found in the Partnership’s Annual Report on 10-K for the year ended December 31, 2007 under Item 9A (T), Controls and Procedures − Management’s Report on Internal Control Over Financial Reporting.

Item 9B.

Other Information

None

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Index

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

The Partnership has no employees of its own and has authorized the Managing General Partner to manage the Partnership’s business through the D&O Agreement. PDC’s directors and executive officers and other key employees receive direct remuneration, compensation or reimbursement solely from PDC, and not the Partnership, with respect to services rendered in their capacity to act on behalf of the Partnership.

Board Management and Risk Oversight

PDC, a publicly-owned Nevada corporation, was organized in 1955. The common stock of PDC is traded on the NASDAQ Global Select Market under the symbol "PETD." The business and affairs of the Partnership are managed by the Managing General Partner through the D&O Agreement, by or under the direction of PDC’s Board of Directors (the “Board”), in accordance with Nevada law and PDC’s By-Laws. The directors’ fiduciary duty is to exercise their business judgment in the best interests of PDC’s shareholders, and in that regard, as Managing General Partner, the best interests of the Partnership and other sponsored drilling partnerships. The Board has adopted Corporate Governance Guidelines that govern the structure and functioning of the Board and establish the Board’s policies on a number of corporate governance issues. With respect to the separation of the offices of Chairman and Chief Executive Officer, or CEO, the Board believes it is most prudent to address this issue as a part of its succession planning process and to make a final determination based on the facts and circumstances at the time of the Chairman’s election, annually or as circumstances warrant.

The Managing General Partner’s Board seeks to understand and oversee critical business risks. Risks are considered in every business decision, not just through Board oversight of the Managing General Partner’s Risk Management system. The Board realizes, however, that is not possible to eliminate all risk, nor is it desirable, and that appropriate risk-taking is essential to achieve the Managing General Partner’s objectives. The Board risk oversight structure provides that management report on critical business risk issues to the Planning and Finance Committee, which includes in part, an oversight function concerning PDC’s liquidity, operational and credit risk management. In this regard, the Planning and Finance Committee also provides similar risk assessment and management process oversight functions for sponsored drilling program partnerships, which includes the Partnership. Other Board committees, however, are active in managing the risks related to such committee’s oversight areas. For example, the Audit Committee reviews many risks and related controls in areas that it considers fundamental to the integrity and reliability for the PDC’s financial statements, such as counterparty risks and derivative program risks. The Managing General Partner’s Board has established the Audit Committee, including a subcommittee which focuses specifically on financial reporting matters of PDC’s sponsored drilling partnerships, to assist the Board in monitoring not only the integrity of the Managing General Partner’s financial reporting systems and internal controls but also PDC’s legal and regulatory compliance. The Board has created a Special Committee that has considered, upon Board request, the potential repurchase of certain of the sponsored drilling partnerships for which PDC serves as Managing General Partner. The Special Committee has not been asked to consider a repurchase of PDC 2003-A Limited Partnership at this time.

Managing General Partner Duties and Resource Allocation

As the Managing General Partner, PDC actively manages and conducts the business of the Partnership under the authority of the D&O Agreement. PDC’s executive officers are full-time employees who devote the entirety of their daily time to the business and operations of PDC. Included in each executive’s responsibilities to PDC is a time commitment, as may be reasonably required of their expertise, to conduct the primary business affairs of the Partnership that include the following:

Profitable development and cost-effective production operations of the Partnership’s natural gas and oil reserves;

Market-responsive natural gas and oil marketing and prudent field operations cost management which support maximum cash flows; and

Technology-enhanced compliant Partnership administration including the following: accounting; revenue and cost allocation; cash management; tax and regulatory agency reporting and filing; and Investor Partner Relations.

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Index

Although the Partnership has not adopted a formal Code of Ethics, the Managing General Partner, has implemented a Code of Business Conduct and Ethics, as amended (“the Code of Conduct”) that applies to all Directors, officers, employees, agents and representatives of the Managing General Partner and consultants. The Managing General Partner’s principal executive officer, principal financial officer and principal accounting officer are subject to additional specific provisions under the Code of Conduct. The Managing General Partner’s Code of Conduct is posted on PDC’s website at www.petd.com.

The Corporate Governance section of the Managing General Partner’s internet site contains additional information, including PDC’s Certificate of Incorporation and By-Laws, written charters for each Board committee and Board policy statements. PDC's internet address is www.petd.com. PDC will make available to Investor Partners audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods. PDC also posts these audited financial statements filed with the SEC, on its internet site.

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Index

Petroleum Development Corporation (dba PDC Energy)

The executive officers and directors of PDC, their principal occupations for the past five years and additional information is set forth below:

Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires

Richard W McCullough	58	Chairman and Chief Executive Officer	2007	2013

Gysle R. Shellum	58	Chief Financial Officer	-	-

R. Scott Meyers	36	Chief Accounting Officer	-	-

Barton R. Brookman, Jr.	48	Senior Vice President Exploration and Production	-	-

Daniel W. Amidon	50	General Counsel and Secretary	-	-

Lance Lauck	47	Senior Vice President Business Development	-	-

Joseph E. Casabona	67	Director	2007	2011

Anthony J. Crisafio	57	Director	2006	2012

Kimberly Luff Wakim	52	Director	2003	2012

Larry F. Mazza	50	Director	2007	2013

David C. Parke	43	Director	2003	2011

Jeffrey C. Swoveland	55	Director	1991	2011

James M. Trimble	62	Director	2009	2013

Richard W. McCullough was appointed Chief Executive Officer of the Company in June 2008 and Chairman of PDC’s Board of Directors in November 2008. From November 2006 until November 2008, he served as the Chief Financial Officer of the Company. Prior to joining PDC, Mr. McCullough served from July 2005 to November 2006 as an energy consultant. From January 2004 to July 2005, he was President and Chief Executive Officer of Gasource, LLC, a marketer of long-term, natural gas supplies in Dallas, Texas. From 2001 to 2003, Mr. McCullough served as an investment banker with J.P. Morgan Securities, Atlanta, Georgia, in the public finance utility group supporting bankers nationally in all natural gas matters. Additionally, Mr. McCullough has held senior positions with Progress Energy, Deloitte and Touche, and the Municipal Gas Authority of Georgia. He holds BS and MS degrees from the University of Southern Mississippi and was a practicing Certified Public Accountant for eight years. Mr. McCullough serves as Chairman of the Executive Committee and serves on the Planning and Finance Committee.

Gysle R. Shellum was appointed Chief Financial Officer in 2008. Prior to joining the Company, Mr. Shellum served as Vice President, Finance and Special Projects of Crosstex Energy, L.P., Dallas, Texas. Mr. Shellum served in this capacity from September 2004 through September 2008. From March 2001 until September 2004, Mr. Shellum served as a consultant to Value Capital, a private consulting firm in Dallas, Texas, where he worked on various projects, including corporate finance and Sarbanes-Oxley Act compliance. Crosstex Energy, L.P. is a publicly traded Delaware limited partnership whose securities are listed on the NASDAQ Global Select Market and is an independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids.

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R. Scott Meyers was appointed Chief Accounting Officer on April 2, 2009. Prior to joining PDC, Mr. Meyers served as a Senior Manager with Schneider Downs Co., Inc., an accounting firm based in Pittsburgh, Pennsylvania. Mr. Meyers served in such capacity from April 2008 to March 2009. Prior thereto, from November 2002 to March 2008, Mr. Meyers was employed by PricewaterhouseCoopers LLP, the last two and one-half years serving as Senior Manager.

Barton R. Brookman, Jr. was appointed Senior Vice President Exploration and Production in March 2008. Previously, Mr. Brookman served as Vice President Exploration and Production since joining PDC in July 2005. Prior to joining PDC, Mr. Brookman worked for Patina Oil and Gas and its predecessor Snyder Oil for 17 years in a series of positions of increasing responsibility, ending his service as Vice President of Operations of Patina.

Daniel W. Amidon was appointed General Counsel and Secretary in July 2007. Prior to his current position, Mr. Amidon was employed by Wheeling-Pittsburgh Steel Corporation beginning in July 2004; he served in several positions including General Counsel and Secretary. Prior to his employment with Wheeling-Pittsburgh Steel, Mr. Amidon worked for J&L Specialty Steel Inc. from 1992 through July 2004 in positions of increasing responsibility, including General Counsel and Secretary. Mr. Amidon practiced with the Pittsburgh law firm of Buchanan Ingersoll PC from 1986 through 1992.

Lance Lauck was appointed Senior Vice President Business Development in August 2009. Previously Mr. Lauck served as Vice President - Acquisitions and Business Development for Quantum Resources Management LLC from 2006 - 2009. From 1988 until 2006, he held various management positions at Anadarko Petroleum Corporation in the areas of acquisitions and divestitures, corporate mergers and business development.

Joseph E. Casabona served as Executive Vice President and member of the Board of Directors of Denver-based Energy Corporation of America, a natural gas exploration and development company, from 1985 until his retirement in May 2007. Mr. Casabona’s responsibilities included strategic planning as well as executive oversight of drilling operations in the continental U.S. and internationally. In 2008, Mr. Casabona became Chief Executive Officer of Paramax Resources Ltd, a junior public Canadian oil & gas company (PMXRF) engaged in the business of acquiring and exploration of oil and gas prospects, primarily in Canada and Idaho. Mr. Casabona serves as Chairman of the Planning and Finance Committee and serves on the Audit Committee.

Anthony J. Crisafio, a Certified Public Accountant, has served as an independent business consultant for more than fifteen years, providing financial and operational advice to businesses in a variety of industries and stages of development. He also serves as an interim Chief Financial Officer and Advisory Board member for a number of privately held companies and has been a Certified Public Accountant for more than thirty years. Mr. Crisafio served as the Chief Operating Officer, Treasurer and member of the Board of Directors of Cinema World, Inc. from 1989 until 1993. From 1975 until 1989, he was employed by Ernst & Young and was a partner with Ernst & Young from 1986 to 1989. He was responsible for several Securities and Exchange Commission (“SEC”) registered client engagements and gained significant experience with oil and gas industry clients and mergers and acquisitions. Mr. Crisafio serves as the Chairman of the Audit Committee and serves on the Compensation Committee.

Kimberly Luff Wakim, an attorney and a Certified Public Accountant, is a Partner with the Pittsburgh, Pennsylvania law firm Thorp, Reed & Armstrong LLP, where she serves as a member of the Executive Committee and is the Practice Group Leader for the Bankruptcy and Financial Restructuring Practice Group. Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990. Ms. Wakim was previously an auditor with Main Hurdman (now KPMG) and was Assistant Controller for PDC from 1982 to 1985. She has been a member of AICPA and the West Virginia Society of CPAs for more than fifteen years. Ms. Wakim serves as Chairman of the Compensation Committee and serves on the Audit Committee and the Nominating and Governance Committee.

Larry F. Mazza is President and Chief Executive Officer of MVB Bank, Inc. in Fairmont, West Virginia. He has been Chief Executive Officer since March 2005, and added the duties of President in January of 2009. Prior to 2005, Mr. Mazza served as Senior Vice President Retail Banking for BB&T and its predecessors in West Virginia, where he was employed from June 1986 to March 2005. A Certified Public Accountant for 26 years, Mr. Mazza also was previously an auditor with KPMG. Mr. Mazza serves on the Nominating and Governance Committee and the Compensation Committee.

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David C. Parke is a Managing Director in the investment banking group of Boenning & Scattergood, Inc., West Conshohocken, Pennsylvania, a full-service investment banking firm. Prior to joining Boenning & Scattergood in November 2006, he was a Director with Mufson Howe Hunter & Company LLC, Philadelphia, Pennsylvania, an investment banking firm, from October 2003 to November 2006. From 1992 through 2003, Mr. Parke was Director of Corporate Finance of Investec, Inc. and its predecessor Pennsylvania Merchant Group Ltd., investment banking companies. Prior to joining Pennsylvania Merchant Group, Mr. Parke served in the corporate finance departments of Wheat First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, Inc., now part of Stifel Nicolaus. Mr. Parke serves on the Planning and Finance Committee, the Compensation Committee and on the Nominating and Governance Committee.

James M. Trimble has served as Managing Director of Grand Gulf Energy, Limited (ASX:GGE), a public company traded on the Australian Exchange, since August 2006. In January 2005, Mr. Trimble founded and has since served as President and Chief Executive Officer of the U.S. subsidiary Grand Gulf Energy Company LLC, an exploration and development company focused primarily on drilling in mature basins in Texas, Louisiana and Oklahoma. From 2000 through 2004, Mr. Trimble was Chief Executive Officer of Elysium Energy and then Tex-Cal Energy LLC, both were privately held oil and gas companies that he was brought in to take through troubled workout solutions. Prior to this, he was Senior Vice President of Exploration and Production for Cabot Oil and Gas (NYSE:COG). From November 2002 until May 2006, he also served as a Director of Blue Dolphin Energy, an independent oil and gas company with operations in the Gulf of Mexico. Mr. Trimble serves on the Planning and Finance Committee and the Compensation Committee.

Jeffrey C. Swoveland is President and Chief Executive Officer of ReGear Life Sciences, Inc. in Pittsburgh, Pennsylvania (previously named Coventina Healthcare Enterprises), which develops and markets medical device products, where he was previously Chief Operating Officer. From 2000 until 2007, Mr. Swoveland served as Chief Financial Officer of Body Media, Inc., a life-science company specializing in the design and development of wearable body monitoring products and services. Prior thereto, Mr. Swoveland held various positions, including Vice-President of Finance, Treasurer and interim Chief Financial Officer with Equitable Resources, Inc., a diversified natural gas company, from 1994 to September 2000. Mr. Swoveland serves as a member of the Board of Directors of Linn Energy, LLC, a public, independent natural gas and oil company. Mr. Swoveland serves as Presiding Independent Director, and serves on the Audit Committee, the Planning and Finance Committee and Executive Committee.

Audit Committee

The Audit Committee is composed entirely of persons whom the Board has determined to be independent under NASDAQ Listing Rule 5605(a)(2), Section 301 of the Sarbanes-Oxley Act of 2002 and Section 10A(m)(3) of the Exchange Act. Anthony J. Crisafio chairs the Audit Committee; other members are Directors Wakim, Casabona and Swoveland. The Board has determined that all four members of the Audit Committee qualify as financial experts as defined by SEC regulations and that all of the Audit Committee members are independent of management.

Item 11.

Executive Compensation

The Partnership does not have any employees or executives of its own. None of PDC's officers or directors receive any direct remuneration, compensation or reimbursement from the Partnership. These persons receive compensation solely from PDC. The Managing General Partner does not believe that PDC’s executive and non-executive compensation structure, available to officers or directors who act on behalf of the Partnership, is reasonably likely to have a materially adverse effect on the Partnership’s operations or conduct of PDC when carrying out duties and responsibilities to the Partnership, as Managing General Partner under the Agreement, or as operator under the D&O Agreement. The management fee and other amounts paid to the Managing General Partner by the Partnership are not used to directly compensate or reimburse PDC’s officers or directors. No management fee was paid to PDC in 2009 or 2008 as the Partnership is not required to pay a management fee other than a one-time fee paid in the initial year of formation per the Agreement. The Partnership pays a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $75 per well per month for Partnership related general and administrative expenses that include accounting, engineering and management of the Partnership by the Managing General Partner. See Item 13, Certain Relationships and Related Transactions, and Director Independence for a discussion of compensation paid by the Partnership to the Managing General Partner.

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Index

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table presents information as of June 30, 2010 concerning the Managing General Partner’s interest in the Partnership and other persons known by the Partnership to own beneficially more than 5% of the interests in the Partnership. Each partner exercises sole voting and investing power with respect to the interest beneficially owned.

	Limited Partnership Units
Person or Group	Number of Units Outstanding Which Represent 80% of Total Partnership Interests (1)		Number of Units Beneficially Owned		Percentage of Total Units Outstanding			Percentage of Total Partnership Interests Beneficially Owned
		424.15
Petroleum Development Corporation (2) (3) (4) (5)		-		18.34		4.32	%		3.46	%
Investor Partners beneficially owning 5% or more, of limited partner interests		-		-		-			-

(1)

Additional general partner units were converted to limited partner interests at the completion of drilling activities. For more information on the Partnership’s unit conversion, see Item 1, Business−General.

(2)

Petroleum Development Corporation (dba PDC Energy), 1775 Sherman Street Suite 3000, Denver, Colorado 80203.

(3)

No director or officer of PDC owns interest in PDC limited partnerships. Pursuant to the Partnership Agreement individual investor partners may present their units to PDC for purchase subject to certain conditions; however, PDC is not obligated to purchase more than 10% of the total outstanding units during any calendar year.

(4)

The Percentage of “Total Partnership Interests Beneficially Owned” by PDC with respect to its limited partnership units repurchased, is determined by multiplying the percentage of limited partnership units repurchased by PDC to total limited partnership units, by the limited partners’ percentage ownership in the Partnership. [(18.34 units/424.15 units)*80% limited partnership ownership]

(5)

In addition to this ownership percentage of limited partnership interest, Petroleum Development Corporation (dba PDC Energy) owns a Managing General Partner interest of 20%.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

Compensation to the Managing General Partner and Affiliates

The Managing General Partner transacts all of the Partnership’s business on behalf of the Partnership. Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the Drilling and Operating Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services or other services for the Partnership at the lesser of cost or competitive prices in the area of operations.

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Index

Industry specialists, employed by PDC to support the Partnership’s business operations include the following:

Geoscientists who identify and develop PDC’s drilling prospects and oversee the drilling process;

Petroleum engineers who plan and direct PDC’s well completions and recompletions, construct and operate PDC’s well and gathering lines, and manage PDC’s production operations;

Petroleum reserve engineers who evaluate well natural gas and oil reserves at least annually and monitor individual well performance against expectations; and

Full-time well tenders and supervisors who operate PDC wells.

Salary and employment benefit costs for the above specialized services are covered by the monthly fees paid to the Managing General Partner as more fully described in the preceding Item 11, Executive Compensation.

PDC retains drilling subcontractors, completion subcontractors and a variety of other subcontractors in the performance of the work of drilling contract wells. In addition to the industry specialists above who provide technical management, PDC may provide services, at competitive rates, from PDC-owned service rigs, a water truck, steel tanks used temporarily on the well location during the drilling and completion of a well, roustabouts and other assorted small equipment and services. A roustabout is a natural gas and oil field employee who provides skilled general labor for assembling well components and other similar tasks. PDC may lay short gathering lines, or may subcontract all or part of the work where it is more cost effective for the Partnership.

See Note 3, Transactions with Managing General Partner and Affiliates to the accompanying financial statements, for information regarding compensation to and transactions with the Managing General Partner and affiliates.

Related Party Transaction Policies and Approval

The Agreement and the D&O Agreement with Petroleum Development Corporation (dba PDC Energy) govern related party transactions, including those described above. The Partnership does not have any written policies or procedures for the review, approval or ratification of transactions with related persons outside of the referenced agreements.

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Index

Other Agreements and Arrangements

Executive officers of the Managing General Partner were eligible to invest in an executive drilling program, as approved by the Board of Directors. These executive officers profited from their participation in the executive drilling program because they invested in wells at cost and did not pay drilling compensation, management fees or broker commissions and therefore obtained an interest in the wells at a reduced price than that which was charged to the investing partners in a Partnership. Investor partners participating in drilling through a partnership were generally charged a profit or markup above the cost of the wells, management fees and commissions at rates which are generally similar to those for this Partnership outlined in Note 3, Transactions with Managing General Partner and Affiliates to the accompanying financial statements.

Through the executive drilling program, certain former executive officers of PDC invested in the wells developed by PDC in which the Partnership invested. The executive program allowed PDC to sell working interests to PDC executive officers in the wells that PDC developed for the Partnership. Participating officers thereby owned parallel undivided working interests in all of the wells that the Partnership has invested in. Prior to the funding of the Partnership, each executive officer who chose to participate in the executive program advised PDC of the dollar amount of his investment participation, and thereby acquired a working interest in the wells in which the Partnership acquired a working interest, the acquired working interest being parallel to the working interest of the Partnership and the investor partners. The officers’ percentage in certain wells is proportionate to the Partnership’s working interest among all of the Partnership’s wells based upon the officers’ investment amount. PDC had the option to sell working interests in these wells to other parties unaffiliated with PDC prior to the funding of the Partnership. The aggregate ownership percentage of these former executive officers ranges from 0.079% to 0.099% in each well drilled by the Partnership. The Board believed that having the executive officers invest in wells with PDC and other investor partners helped to create a commonality of interests much like share ownership creates a commonality of interests between the shareholders and executive officers. As of December 31, 2009, no current executive officer of the Managing General Partner owns any beneficial interest in the Partnership.

Director Independence

The Partnership has no directors. The Partnership is managed by the Managing General Partner. See Item 10, Directors, Executive Officers and Corporate Governance.

Item 14.

Principal Accountant Fees and Services

The following table presents amounts charged by the Partnership’s independent registered public accounting firm, PricewaterhouseCoopers LLP (“PwC”) for the years described:

	Year Ended December 31,
Type of Service	2009		2008

Audit Fees (1)	$	105,000	$	105,000
Tax Fees (2)		6,000		6,000
Total fees	$	111,000	$	111,000

(1)

Audit fees consist of professional service fees billed for audit of the Partnership’s annual financial statements which accompany the Partnership’s Annual Report on Form 10-K, including reviews of the Partnership’s quarterly condensed interim financial statements which accompany this report.

(2)

Tax fees consist primarily of professional services fees billed for preparation of the Partnership’s annual IRS Form 1065 and individual partners’ Schedule K-1.

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Audit Committee Pre-Approval Policies and Procedures

The Sarbanes-Oxley Act of 2002 requires that all services provided to the Partnership by its independent registered public accounting firm be subject to pre-approval by the Audit Committee or authorized members of the Committee. The Partnership has no Audit Committee. The Audit Committee of PDC, as Managing General Partner, has adopted policies and procedures for pre-approval of all audit services and non-audit services to be provided by the Partnership's independent registered public accounting firm. Services necessary to conduct the annual audit must be pre-approved by the Audit Committee annually at a meeting. Permissible non-audit services to be performed by the independent registered public accounting firm may also be approved on an annual basis by the Audit Committee if they are of a recurring nature. Permissible non-audit services to be conducted by the independent registered public accounting firm, which are not eligible for annual pre-approval, must be pre-approved individually by the full Audit Committee or by an authorized Audit Committee member. Actual fees incurred for all services performed by the independent registered public accounting firm will be reported to the Audit Committee after the services are fully performed. The duties of the Committee are described in the Audit Committee Charter, which is available at the Managing General Partner, PDC’s, website under Corporate Governance.

PART IV

Item 15.

Exhibits, Financial Statement Schedules

(a)	The index to Financial Statements is located on page F-1.

(b)	Exhibits index.

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing

Date

Filed

Herewith

3.1

Limited Partnership Agreement

10-K

000-50615

3.1

10/08/2010

3.2

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

10-K

000-50615

3.2

10/08/2010

10.1

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

10-K

000-50615

10.1

10/08/2010

10.2

Form of assignment of leases to the Partnership

10-K

000-50615

10.2

10/08/2010

10.3

Audited Consolidated Financial Statements for the year ended December 31, 2009 of Petroleum Development Corporation (dba PDC Energy) and its subsidiaries, as Managing General Partner of the Partnership

10-K

000-07246

03/04/2010

10.4

Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A

Amend 3

000-53201

10.3

03/31/2009

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Index

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing

Date

Filed

Herewith

10.5

Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982-A Limited and Cattle Creek Company, dated October 14, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A

Amend 3

000-53201

10.4

03/31/2009

10.6

Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and SHF Partnership, a Colorado general partnership, Trailblazer Oil and Gas, Inc., Alfa Resources, Inc., Pulsar Oil and Gas, Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert Lanari, an individual, and Toby A Martinez, an individual, dated September 21, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A

Amend 3

000-53201

10.5

03/31/2009

10.7

Domestic Crude Oil Purchase Agreement with ConocoPhillips Company, dated January 1, 1993, as amended by agreements with Teppco Crude Oil, LLC dated August 2, 2007; September 24, 2007; October 17, 2007; January 7, 2008; January 15, 2008; and April 17, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A

Amend 3

000-53201

10.6

03/31/2009

10.8

Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and Petroleum Development Corporation, dated as of June 1, 2006 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A

Amend 3

000-53201

10.7

03/31/2009

10.9

Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and Petroleum Development Corporation, dated April 22, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-Q

000-53201

10.1

05/18/2009

- 48 -

Index

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing

Date

Filed

Herewith

31.1

Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership.

31.2

Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership.

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 (dba PDC Energy), the Managing General Partner of the Partnership.

99.2

Report of Independent Petroleum Consultants−Ryder Scott Company, LP

- 49 -

Index

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 2003-A Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

of Petroleum Development Corporation (dba PDC Energy)

October 8, 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

/s/ Richard W. McCullough	Chairman and Chief Executive Officer	October 8, 2010
Richard W. McCullough	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	October 8, 2010
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	October 8, 2010
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal accounting officer)

/s/ Kimberly Luff Wakim	Director	October 8, 2010
Kimberly Luff Wakim	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant

/s/ Anthony J. Crisafio	Director	October 8, 2010
Anthony J. Crisafio	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant

/s/ Jeffrey C. Swoveland	Director	October 8, 2010
Jeffrey C. Swoveland	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant

/s/ Joseph E. Casabona	Director	October 8, 2010
Joseph E. Casabona	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant

- 50 -

Index

PDC 2003-A LIMITED PARTNERSHIP

Index to Financial Statements

Report of Independent Registered Public Accounting Firm	F-2

Balance Sheets - December 31, 2009 and 2008	F-3

Statements of Operations - For the Years Ended December 31, 2009 and 2008	F-4

Statements of Partners' Equity - For the Years Ended December 31, 2009 and 2008	F-5

Statements of Cash Flows - For the Years Ended December 31, 2009 and 2008	F-6

Notes to Financial Statements	F-7

Supplemental Natural Gas and Oil Information - Unaudited	F-27

Unaudited Condensed Quarterly Financial Statements:

Balance Sheets - 2009	F-30
Balance Sheets - 2008	F-31

Statements of Operations - 2009	F-32
Statements of Operations - 2008	F-33

Statements of Cash Flows - 2009	F-34
Statements of Cash Flows - 2008	F-35

Notes to Unaudited Condensed Quarterly Financial Statements	F-36

F-1

Index

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of the PDC 2003-A Limited Partnership,

In our opinion, the accompanying balance sheets and the related statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of PDC 2003-A Limited Partnership (the "Partnership") at December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 3 to the financial statements, the Partnership has significant related party transactions with Petroleum Development Corporation and its subsidiaries.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

October 8, 2010

F-2

Index

PDC 2003-A LIMITED PARTNERSHIP

Balance Sheets

As of December 31, 2009 and 2008

Assets	2009			2008

Current assets:
Cash and cash equivalents	$	133		$	36,809
Accounts receivable		64,246			41,288
Oil inventory		11,442			20,380
Due from Managing General Partner-derivatives		94,751			345,160
Due from Managing General Partner-other, net		8,289			198,081
Total current assets		178,861			641,718


Natural gas and oil properties, successful efforts method, at cost		9,361,153			9,309,632
Less: Accumulated depreciation, depletion and amortization		(5,344,051	)		(4,664,290	)
Natural gas and oil properties, net		4,017,102			4,645,342

Due from Managing General Partner-derivatives		76,808			146,461
Other assets		19,132			12,534
Total noncurrent assets		4,113,042			4,804,337


Total Assets	$	4,291,903		$	5,446,055


Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	7,588		$	12,326
Due to Managing General Partner-derivatives		73,549			-
Total current liabilities		81,137			12,326

Due to Managing General Partner-derivatives		234,481			27,152
Asset retirement obligations		111,671			83,859
Total liabilities		427,289			123,337

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		774,216			1,065,836
Limited Partners - 424.15 units issued and outstanding		3,090,398			4,256,882
Total Partners' equity		3,864,614			5,322,718

Total Liabilities and Partners' Equity	$	4,291,903		$	5,446,055

See accompanying notes to financial statements.

F-3

Index

PDC 2003-A LIMITED PARTNERSHIP

Statements of Operations

For the Years Ended December 31, 2009 and 2008

	2009			2008
Revenues:
Natural gas and oil sales	$	654,225		$	1,212,242
Commodity price risk management (loss) gain, net		(214,980	)		536,819
Total revenues		439,245			1,749,061

Operating costs and expenses:
Natural gas and oil production costs		267,858			459,281
Direct costs - general and administrative		76,747			39,331
Depreciation, depletion and amortization		679,761			457,783
Accretion of asset retirement obligations		2,073			4,560
Total operating costs and expenses		1,026,439			960,955

(Loss) income from operations		(587,194	)		788,106

Interest expense		(2,535	)		-
Interest income		12,873			21,843

Net (loss) income	$	(576,856	)	$	809,949

Net (loss) income allocated to partners	$	(576,856	)	$	809,949
Less: Managing General Partner interest in net (loss) income		(115,371	)		161,990
Net (loss) income allocated to Investor Partners	$	(461,485	)	$	647,959

Net (loss) income per Investor Partner unit	$	(1,088	)	$	1,528

Investor Partner units outstanding		424.15			424.15

See accompanying notes to financial statements.

F-4

Index

PDC 2003-A LIMITED PARTNERSHIP

Statements of Partners' Equity

For the Years Ended December 31, 2009 and 2008

				Managing
	Investor			General
	Partners			Partner			Total

Balance, December 31, 2007		4,390,033			1,099,123			5,489,156

Distributions to partners		(781,110	)		(195,277	)		(976,387	)

Net income		647,959			161,990			809,949

Balance, December 31, 2008		4,256,882			1,065,836			5,322,718

Distributions to partners		(704,999	)		(176,249	)		(881,248	)

Net loss		(461,485	)		(115,371	)		(576,856	)

Balance, December 31, 2009	$	3,090,398		$	774,216		$	3,864,614

See accompanying notes to financial statements.

F-5

Index

PDC 2003-A LIMITED PARTNERSHIP

Statements of Cash Flows

For the Years Ended December 31, 2009 and 2008

	2009			2008
Cash flows from operating activities:
Net (loss) income	$	(576,856	)	$	809,949
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		679,761			457,783
Accretion of asset retirement obligations		2,073			4,560
Unrealized loss (gain) on derivative transactions		600,940			(504,614	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(22,958	)		69,996
Decrease (increase) in oil inventory		8,938			(20,380	)
Increase in other assets		(6,598	)		(7,521	)
Decrease in accounts payable and accrued expenses		(4,738	)		(1,721	)
Decrease in due from Managing General Partner, other - net		189,792			208,901
Net cash provided by operating activities		870,354			1,016,953

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(25,782	)		(36,897	)
Net cash used in investing activities		(25,782	)		(36,897	)

Cash flows from financing activities:
Distributions to Partners		(881,248	)		(976,387	)
Net cash used in financing activities		(881,248	)		(976,387	)

Net (decrease) increase in cash and cash equivalents		(36,676	)		3,669
Cash and cash equivalents, beginning of year		36,809			33,140
Cash and cash equivalents, end of year	$	133		$	36,809


Cash payments for:
Interest	$	2,535		$	-

Supplemental disclosure of non-cash activity:
Asset retirement obligation, with corresponding increase to oil and gas properties	$	25,739		$	-

See accompanying notes to financial statements.

F-6

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Financial Statements

Note 1 – General

PDC 2003-A Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and oil properties. Business operations of the Partnership commenced upon closing of an offering for the sale of Partnership units. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the Partnership’s business. 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. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of June 30, 2010, there were 435 Investor Partners. Petroleum Development Corporation (dba PDC Energy) is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership. According to the terms of the Limited Partnership Agreement, revenues, costs, and cash distributions of the Partnership are allocated 80% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. Through June 30, 2010, the Managing General Partner has repurchased 18.34 units of Partnership interests from Investor Partners at an average price of $8,840 per unit.

The following table presents Partnership formation and organization information through the completion of the drilling phase on January 13, 2004:

				Number of Partner Units
PDC 2003-A Limited Partnership Information	Date	Number of Partners		Additional General Partner Units			Limited Partner Units		Equity Percentage			Amount (millions)

West Virginia Limited Partnership Formation	June 3, 2002
Limited Partnership Termination Date	December 31, 2050

Public Sale of Securities and Funding	April 30, 2003
Investor Partners (1) Unit Cost: $20,000			446		415.15			9.00		80.00	%	$	8.5
PDC, Managing General Partner										20.00	%		1.8
Total funding													10.3
Syndication costs paid to third-party brokers													(0.9	)
Management Fee Paid to PDC													(0.2	)
Net funding available for drilling activities										100.00	%	$	9.2

Conversion of additional General Partners to Limited Partners	January 13, 2004				(415.15	)		415.15
Limited Partnership Units after Conversion					-			424.15

(1)

Executive Drilling Program

Executive officers of the Managing General Partner were eligible to invest in an executive drilling program as approved by the Board of Directors. These executive officers profited from their participation in the executive drilling program because they invested in wells at cost and did not pay drilling compensation, management fees or broker commissions and therefore obtained an interest in the wells at a reduced price than that which was charged to the investing partners in a Partnership. Investor partners participating in drilling through a partnership were generally charged a profit or markup above the cost of the wells, management fees and commissions. See Note 3, Transactions with Managing General Partner and Affiliates.

Through the executive drilling program, certain former executive officers of PDC have invested in the wells developed by PDC in which the Partnership invested. The executive program allowed PDC to sell working interests to PDC executive officers in the wells that PDC developed for the Partnership. Participating officers thereby owned parallel undivided working interests in all of the wells that the Partnership has invested in. Prior to the funding of the Partnership, each executive officer who chose to participate in the executive program advised PDC of the dollar amount of his investment participation, and thereby acquired a working interest in the wells in which the Partnership acquired a working interest, the acquired working interest being parallel to the working interest of the Partnership and the investor partners. The officers’ percentage in certain wells is proportionate to the Partnership’s working interest among all of the Partnership’s wells based upon the officers’ investment amount. PDC also had the option to sell working interests in these wells, also prior to the funding of the Partnership, to other parties unaffiliated with PDC. The aggregate ownership percentage of these former executive officers ranged from 0.079% to 0.099% in each well drilled by the Partnership. The Board believed that having the executive officers invest in wells with PDC and other investor partners helped to create a commonality of interests much like share ownership creates a commonality of interests between the shareholders and executive officers. As of December 31, 2009, no current executive officer owns any beneficial interest in the Partnership.

F-7

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Financial Statements

Note 2 - Summary of Significant Accounting Policies

Basis of Presentation

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of the Partnership.

Cash and Cash Equivalents

The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. Prior to October 3, 2008, the balance in the Partnership’s account was insured by Federal Deposit Insurance Corporation, or FDIC, up to $100,000. As a result of the Emergency Economic Stability Act, the FDIC limit was raised to $250,000 effective October 3, 2008 through December 31, 2009 and subsequently extended through December 31, 2013. The Partnership has not experienced losses in any such accounts to date and limits the Partnership’s exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.

Accounts Receivable and Allowance for Doubtful Accounts

The Partnership’s accounts receivable are from purchasers of natural gas and oil production. The Partnership sells substantially all of its natural gas and oil to customers who purchase natural gas and oil from other partnerships managed by the Partnership’s Managing General Partner. Inherent to the Partnership’s industry is the concentration of natural gas and oil sales made to few customers. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that its customers may be similarly affected by changes in economic, industry or other conditions.

As of December 31, 2009 and 2008, the Partnership did not record an allowance for doubtful accounts. Historically, neither PDC nor any of the other partnerships managed by the Partnership’s Managing General Partner have experienced significant losses on accounts receivable. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. The Partnership did not incur any losses on accounts receivable for the years ended December 31, 2009 and 2008. For more information concerning the Partnership’s concentration of credit risk and the Managing General Partner’s evaluation of that risk, see Note 7, Concentration of Credit Risk, below.

Commitments

As Managing General Partner, PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of the Partnership’s wells as required by governmental agencies. If a government agency were required to access these performance bonds to cover plugging, reclaiming or abandonment costs on a Partnership well, the Partnership would be obligated to fund any amounts in excess of funds previously withheld by the Managing General Partner to cover these expenses.

F-8

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Financial Statements

Inventories

Oil inventories are stated at the lower of average lifting cost or market.

Natural Gas and Oil Properties

The Partnership accounts for its natural gas and oil properties (the “Properties”) under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing natural gas and oil reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved natural gas and oil reserves. See Supplemental Natural Gas and Oil Information – Unaudited, Net Proved Natural Gas and Oil Reserves for additional information regarding the Partnership’s reserve reporting. In accordance with the Agreement, all capital contributed to the Partnership after deducting syndication costs and a one-time management fee was used solely for the drilling of natural gas and oil wells. Accordingly, all such funds were advanced to the Managing General Partnership as of the last day of the year in which the Partnership was formed. The Partnership does not maintain an inventory of undrilled leases.

Partnership estimates of proved reserves are based on those quantities of natural gas and oil which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations. Annually, the Managing General Partner engages independent petroleum engineers to prepare a reserve and economic evaluation of the Partnership’s properties on a well-by-well basis as of December 31. Additionally, the Partnership adjusts natural gas and oil reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas and oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reported reserve estimates represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our depreciation, depletion and amortization (“DD&A”) expense, a change in the Partnership’s estimated reserves could have an effect on the Partnership’s net income.

The Partnership assesses impairment of capitalized costs of proved natural gas and oil properties, 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 prices at which management reasonably estimates commodities to be sold. The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and oil. Downward revisions in estimates of the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and therefore a possible impairment of the Partnership’s natural gas and oil properties. If during the completion of the impairment test, 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, which is predominantly unobservable data or inputs (Level 3) and is measured by the amount by which the net capitalized costs exceed fair value. The Partnership’s estimated production used in the impairment testing is taken from the annual reserve report, which is presented in the Supplemental Natural Gas and Oil Information–Unaudited, Net Proved Natural Gas and Oil Reserves. Estimated undiscounted future net cash flows are determined using prices from the forward price curve. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and oil reserves. Due to the availability of new reserve information, the Partnership reviewed its proved oil and natural gas properties for impairment at December 31, 2009. The Partnership recognized no impairment of its natural gas and oil properties for the year ended December 31, 2009 or during any previous period since the Partnership’s began operating in 2003.

F-9

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Financial Statements

Revenue Recognition

Natural Gas Sales. Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well. Virtually all of the Managing General Partner’s contracts pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available gas supplies.

The Partnership currently uses the “Net-Back” method of accounting for transportation arrangements of natural gas sales. The Managing General Partner markets the Partnership’s natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Partnership’s customers and reflected in the wellhead price.

Oil Sales. Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable. The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of its oil production.

The Partnership’s crude oil production is sold to purchasers at or near the Partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

The Partnership presents any taxes collected from customers and remitted to a government agency on a net basis in its statements of operations in accordance with accounting standards for revenue recognition regarding taxes collected from customers and remitted to governments.

Asset Retirement Obligations

The Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spudded. 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. The asset retirement obligations are accreted, over the estimated life of the related asset, for the change in present value. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense. 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 costs for future dismantlement, restoration, reclamation and abandonment and changes in the estimate of retirement obligation settlement at the end of each well’s productive service life. See Note 8, Asset Retirement Obligations for a reconciliation of asset retirement obligation activity.

Derivative Financial Instruments

The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and oil. Price risk represents the potential risk of loss from adverse changes in the market price of natural gas and oil commodities. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations using commodity derivative instruments. The Managing General Partner’s policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

F-10

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Financial Statements

All derivative assets and liabilities are recorded on the balance sheets at fair value. Recognition and classification of realized and unrealized gains and losses resulting from maturities and changes in fair value of open derivatives depends on the purpose for issuing or holding the derivative. Since PDC, as Managing General Partner, does not designate the Partnership’s derivative instruments as hedges, the Partnership does not currently qualify for the use of hedge accounting. Therefore, changes in the fair value of the Partnership’s derivative instruments are recorded in the Partnership’s statements of operations and the Partnership’s net income is subject to greater volatility than if the Partnership’s derivative instruments qualified for hedge accounting. Changes in the fair value of derivative instruments related to the Partnership’s natural gas and oil sales are recorded in the line captioned, “Commodity price risk management, net.”

Validation 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 the Partnership’s pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments, for a discussion of the Partnership’s derivative fair value measurements and a summary fair value table of open positions as of December 31, 2009 and 2008.

Income Taxes

Since the taxable income or loss of the Partnership is reported in the separate tax returns of the individual investor partners, no provision has been made for income taxes by the Partnership.

Production Tax Liability

The Partnership is responsible for production taxes which are primarily made up of severance and property taxes to be paid to the states and counties in which the Partnership produces natural gas and oil. The Partnership’s share of these taxes is expensed to the account “Natural gas and oil production costs.” The Partnership’s production taxes payable are included in the caption “Accounts payable and accrued expenses” on the Partnership’s balance sheets.

Use of Estimates

The Partnership has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these Partnership financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas and oil reserves, future cash flows from natural gas and oil properties which are used in assessing impairment of long-lived assets, estimated production and severance taxes, asset retirement obligations, and valuation of derivative instruments.

Recently Adopted 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 United States of America Generally Accepted Accounting Principles (“U. S. GAAP”). Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for Securities and Exchange, or 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 financial statements.

F-11

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Financial Statements

Business Combinations

In December 2007, the FASB revised guidance for business combinations, goodwill and other intangible assets by requiring the use of the acquisition method for business combinations whose acquisition date is on or after January 1, 2009, with earlier adoption prohibited. The income tax provisions became effective as of that date for all acquisitions, regardless of the acquisition date. The new guidance, as subsequently amended in April 2009, requires:

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

The 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 are to be expensed as incurred.

Certain acquired contingencies are to be treated as contingent consideration and measured both initially and subsequently at fair value, if fair value can be reasonably estimated.

The FASB’s comprehensive revised guidance for business combinations also amends other related authoritative guidance including:

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.

Accounting for uncertainty in 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.

The Partnership adopted these provisions effective January 1, 2009, for which the provisions will be applied prospectively in the Partnership’s accounting for future acquisitions, if any. The adoption had no impact on the Partnership’s financial statements.

Consolidation – Non-controlling Interests

In December 2007, the FASB issued, in conjunction with the revised standards for business combinations previously noted, revised guidance regarding non-controlling interests in consolidated financial statements that requires the accounting and reporting for minority interests to be recharacterized as non-controlling interests and classified as a component of equity. Additionally, the revised standards establish reporting requirements for sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The Partnership adopted the provisions of this revised standard effective January 1, 2009. The adoption had no impact on the Partnership’s financial statements.

Derivatives and Hedging Disclosures

In April 2007, the FASB issued an accounting directive regarding the conditions when offsetting of fair value amounts for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement for derivative instruments, is permissible. This new accounting principle applied to fiscal years beginning after November 15, 2007, with early adoption permitted. The January 1, 2008 adoption of this directive had no impact on the Partnership’s financial statements.

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Notes to Financial Statements

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 financial statements. See Note 5, Derivative Financial Instruments.

Fair Value Measurements and Disclosures

The Partnership adopted the FASB’s new accounting standards for fair value measurement of assets and liabilities, effective January 1, 2008. These new fair value measurements define fair value, establish a framework for measuring fair value and expands disclosures related to fair value measurements that apply broadly to financial and nonfinancial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but did not expand the application of fair value accounting to any new circumstances. Effective January 1, 2008, the Partnership applied the new provisions to its recurring measurements and the impact was not material to the Partnership’s underlying fair values and no amounts were recorded relative to the cumulative effect of a change in accounting principle. In February 2008, the FASB delayed the effective date of the new standard by one year (to January 1, 2009) for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Partnership adopted the new standard’s provisions on January 1, 2009 to the Partnership’s nonfinancial assets and liabilities that included those initially measured at fair value, such as the Partnership’s asset retirement obligations, and the adoption had no material impact on the Partnership’s financial statements. See Note 4, Fair Value of Financial Instruments

The FASB’s guidance for reporting selected financial assets and liabilities at fair value became effective for the Partnership on January 1, 2008; however, the Partnership has not and does not intend to measure additional financial assets and liabilities at fair value. The new guidance permits entities to choose to measure, at fair value, many financial instruments and certain other items that are not currently required to be measured at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The new standards establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities.

In October 2008, the FASB issued clarifying guidance and key criteria for determining the fair value of a financial asset in a market that is not active. This guidance was effective upon issuance and did not have a material impact on the Partnership’s financial statements.

The FASB’s amendments for determining fair value during periods of declining activity and interim disclosures about fair value of financial instruments were early adopted by the Partnership on April 1, 2009 and did not have a material impact on the Partnership’s financial statements. In April 2009, the FASB amended fair value measurements and disclosures about fair value measurement standards, as follows:

Affirms that the objective of fair value when the market for an asset is not active is the price that would be received to sell the asset in an orderly transaction; clarifies and includes additional factors for determining whether there has been a significant decrease in market activity for an asset when the market for that asset is not active; eliminates the proposed presumption that all transactions are distressed (not orderly) unless proven otherwise and instead requires an entity to base its conclusion about whether a transaction was not orderly on the weight of the evidence; requires an entity to disclose a change in valuation technique (and the related inputs) resulting from the application of the amendment and to quantify its effects, if practicable; and applies to all fair value measurements when appropriate.

Requires an entity to provide disclosures about fair value of financial instruments in interim financial information and requires those disclosures in summarized financial information at interim reporting periods. Pursuant to this amendment, a reporting entity shall include disclosures about the fair value of its financial instruments whenever it issues summarized financial information for interim reporting periods. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position.

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Notes to Financial Statements

In August 2009, the FASB issued changes regarding fair value measurements and disclosures to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities. These changes clarify existing guidance that in circumstances in which a quoted price in an active market for the identical liability is not available, an entity is required to measure fair 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, or another valuation technique that is consistent with the principles of fair value measurements, such as an income approach (e.g., present value technique). This guidance also states that both a quoted price in an active market for the identical liability and a quoted price for the identical liability when traded as an 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, 2009. The adoption of these changes did not have a material impact on the Partnership’s financial statements.

Natural Gas and Oil Reserve Estimation and Reporting

In January 2009, the SEC published its final rule regarding the modernization of natural gas and oil reporting, which modifies the SEC’s reporting and disclosure rules for natural gas and oil reserves. The most notable changes of the final rule include the replacement of the single day period-end pricing to value natural gas and oil reserves to a 12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements were effective for the Partnership as of December 31, 2009. Early adoption was not permitted.

In January 2010, the FASB issued changes in its natural gas and oil reserve estimation and disclosure requirements to align them with the SEC's final rule discussed above. These changes were also effective for the Partnership as of December 31, 2009.

The Partnership applied the above changes to the Partnership’s financial statements of and for the year ended December 31, 2009. As a result, the Partnership’s fourth quarter DD&A calculation was based on proved developed producing reserves that were calculated using the new SEC reserve reporting guidelines; whereas, DD&A calculations for the first three quarters of 2009 were based on the prior methodology. The impact of using the 12-month average pricing methodology specified under the new SEC reporting rules resulted in an increase of the Partnership’s fourth quarter DD&A expense of approximately $8,000.

Subsequent Events

In May 2009, the 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 Subsequent Events, below.

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Notes to Financial Statements

Recently Issued Accounting Standards

Consolidation – Variable Interest Entities

In June 2009, the FASB issued changes regarding 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. These changes became effective for the Partnership on January 1, 2010 and did not have a material impact on the Partnership’s financial statements when adopted in 2010.

Fair Value Measurements and Disclosures

In January 2010, the FASB issued changes clarifying existing disclosure requirements and requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. These changes will be effective for the Partnership’s financial statements issued for the first interim or annual reporting period beginning after December 15, 2009, except for gross presentation of the Level 3 roll forward, which will become effective for annual reporting periods beginning after December 15, 2010. The Partnership's adoption did not have a material effect on the Partnership's financial statements and related disclosures.

Internal Control over Financial Reporting in Exchange Act Periodic Reports

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

Subsequent Events

The Managing General Partner has evaluated the Partnership’s activities subsequent to December 31, 2009 through the issuance of the financial statements, and has concluded that no material subsequent events have occurred that would require additional recognition in the Partnership’s financial statements or disclosure in the notes to the Partnership’s financial statements.

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Notes to Financial Statements

Note 3 - Transactions with Managing General Partner and Affiliates

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received 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 sheets 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-other, net which remain undistributed or unsettled with the Partnership’s investors as of the dates indicated.

	December 31,
	2009			2008

Natural gas and oil sales revenues collected from the Partnership's third-party customers	$	71,800		$	101,750
Commodity Price Risk Management, Realized Gains		58,656			110,938
Other (1)		(122,167	)		(14,607	)
Total Due (to) from Managing General Partner-other, net	$	8,289		$	198,081

(1)

All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner. Except as noted below, the majority of these are operating costs or general and administrative costs which have not been deducted from distributions.

As of December 31, 2008, certain amounts recorded by the Partnership as assets in the account “Due from (to) Managing General Partner – other, net” included amounts that were being held as restricted cash by the Managing General Partner, PDC, on behalf of the Partnership for the over-withholding of production taxes related to Partnership production prior to 2007, including accrued interest thereon. During September 2009, the Partnership collected these amounts totaling $0.5 million, from the Managing General Partner.

Additionally, certain amounts representing royalties on Partnership production paid in September 2009 were recorded by the Partnership as liabilities in the account “Due from (to) Managing General Partner-other, net.” These amounts, which totaled approximately $84,000 including legal fees of approximately $7,000, represented the Partnership’s share of the court approved royalty litigation payment and settlement, more fully described in Note 9, Commitments and Contingencies. During September 2009, all settlement costs related to this litigation were paid by the Partnership, to the Managing General Partner.

For more information concerning the September 2009 settlement of the Partnership’s production tax refund receivable and Colorado royalty litigation settlement liability during September 2009, and its related impact to the Partnership’s cash distributions for the month of September 2009, see Note 6, Partners’ Equity and Cash Distributions.

Commencing with the 36th month of well operations, the Managing General Partner started withholding from monthly Partnership distributable cash, amounts to be used to fund statutorily-mandated well plugging, abandonment and environmental site restoration expenditures. A Partnership well may be sold or plugged, reclaimed and abandoned, with consent of all non-operators, when depleted or an evaluation is made that the well has become uneconomical to produce. Per-well plugging fees withheld during 2009 and 2008 were $50 per well each month the well produced. The total amount withheld from Partnership distributable cash for the purposes of funding future Partnership obligations, is recorded on the balance sheets in the long-term asset line captioned, “Other Assets.”

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Notes to Financial Statements

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner and its affiliates for years ended December 31, 2009 and 2008. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Natural gas and oil production costs” on the statements of operations.

	Year Ended December 31,
	2009		2008

Well operations and maintenance (1)	$	213,907	$	358,243
Gathering, compression and processing fees (2)		22,972		19,935
Direct costs - general and administrative (3)		76,747		39,331
Cash distributions (4) (5)		206,014		220,892

(1) Under the D&O Agreement, the Managing General Partner, as operator of the wells, receives payments for well charges and lease operating supplies and maintenance expenses from the Partnership when the wells begin producing.

Well charges. The Managing General Partner receives reimbursement at actual cost for all direct expenses incurred on behalf of the Partnership, monthly well operating charges for operating and maintaining the wells during producing operations, which reflects a competitive field rate, and a monthly administration charge for Partnership activities.

Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the Drilling and Operating Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provided equipment or supplies, performed salt water disposal services and other services for the Partnership at the lesser of cost or competitive prices in the area of operations.

The Managing General Partner, as operator, bills non-routine operations and administration costs to the Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between the Partnership and the actual provider of operator services. In no event is any consideration received for operator services duplicative of any consideration or reimbursement received under the Agreement.

The well operating, or well tending, charges cover all normal and regularly recurring operating expenses for the production, delivery and sale of natural gas and oil, such as:

well tending, routine maintenance, and adjustment;

reading meters, recording production, pumping, maintaining appropriate books and records; and

preparing production related reports to the Partnership and government agencies.

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Notes to Financial Statements

The well supervision fees do not include costs and expenses related to:

the purchase or repairs of equipment, materials or third-party services;

the cost of compression and third-party gathering services or gathering costs;

brine disposal; and

rebuilding of access roads.

These costs are charged at the invoice cost of the materials purchased or the third-party services performed.

Lease Operating Supplies and Maintenance Expense. The Managing General Partner and its affiliates may enter into other transactions with the Partnership for services, supplies and equipment during the production phase of the Partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.

(2) Under the Agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the gas produced by the Partnership to interstate pipeline systems, local distribution companies and/or end-users in the area from the point the natural gas from the well is commingled with natural gas from other wells. In such a case, the Managing General Partner uses gathering systems already owned by PDC, or PDC constructs the necessary facilities if no such line exists. In such a case, the Partnership pays a gathering, compression and processing fee directly to the Managing General Partner at competitive rates. If a third-party gathering system is used, the Partnership pays the gathering fee charged by the third-party gathering the gas.

(3) The Managing General Partner is reimbursed by the Partnership for all direct costs expended by them on the Partnership’s behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.

(4) The Agreement provides for the allocation of cash distributions 80% to the Investors Partners and 20% to the Managing General Partner. The Investor Partner cash distributions during 2009 and 2008 include $29,765 and $25,615, respectively, for Investor Partner units repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 6, Partners’ Equity and Cash Distributions.

(5) Distributions to Partners in 2009 were impacted by non-recurring items. See Note 6, Partners’ Equity and Cash Distributions, below for detailed information on these transactions.

Note 4 - Fair Value Measurements

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

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Notes to Financial Statements

Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. Included in Level 1 are commodity derivative instruments for New York Mercantile Exchange, or NYMEX, based fixed-price natural gas swaps and collars.

Level 3 – Unobservable inputs for the asset or 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 derivative instruments for Colorado Interstate Gas, or CIG, based fixed-price natural gas swaps, collars, 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. For more information concerning the Partnership’s concentration of credit risk and the Managing General Partner’s evaluation of that risk, see Note 7, Concentration of Credit Risk, below.

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 years ended December 31, 2009 and 2008.

	Level 1			Level 3			Total

As of December 31, 2008
Assets:
Commodity based derivatives	$	-		$	491,621		$	491,621
Total assets		-			491,621			491,621

Liabilities:
Commodity based derivatives		-			-			-
Basis protection derivative contracts		-			(27,152	)		(27,152	)
Total liabilities		-			(27,152	)		(27,152	)

Net asset	$	-		$	464,469		$	464,469

As of December 31, 2009
Assets:
Commodity based derivatives	$	77,667		$	93,892		$	171,559
Total assets		77,667			93,892			171,559

Liabilities:
Commodity based derivatives		(5,255	)		(27,897	)		(33,152	)
Basis protection derivative contracts		-			(274,878	)		(274,878	)
Total liabilities		(5,255	)		(302,775	)		(308,030	)

Net asset (liability)	$	72,412		$	(208,883	)	$	(136,471	)

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Notes to Financial Statements

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

	December 31,
	2009			2008
Fair value, net asset (liability) beginning of year	$	464,469		$	(40,145	)
Changes in fair value included in statement of operations line item:
Commodity price risk management (loss) gain, net		(287,392	)		536,819
Settlements		(385,960	)		(32,205	)
Fair value, net (liability) asset end of year	$	(208,883	)	$	464,469

Change in unrealized gains (losses) relating to assets (liabilities) still held as of December 31, 2009 and December 31, 2008, respectively, included in statement of operations line item:
Commodity price risk management (loss), net	$	(301,498	)	$	-

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 current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

See Note 2, Summary of Significant Accounting Policies−Natural Gas and Oil Properties and Asset Retirement Obligations, for a discussion of how the Partnership determined fair value on these obligations.

Note 5 - Derivative Financial Instruments

The Partnership’s results of operations and operating cash flows are affected by changes in market prices for natural gas and oil. To mitigate a portion of the Partnership’s exposure to adverse market changes, the Managing General Partner utilizes an economic hedging strategy for the Partnership’s natural gas and oil sales, in which PDC, as Managing General Partner, enters into derivative contracts on behalf of the Partnership to protect against price declines in future periods. While the Managing General Partner structures these derivatives to reduce the Partnership’s 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 Managing General Partner believes the Partnership’s derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of June 30, 2010, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 215,619 MMbtu of natural gas and 3,634 Bbls of oil. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

The Managing General Partner uses natural gas and oil commodity derivative instruments to manage price risk for PDC as well as its sponsored drilling partnerships. The Managing General Partner sets these instruments for PDC and the various partnerships managed by PDC jointly by area of operations. Prior to September 30, 2008, as production volumes changed, the allocation of derivative positions between PDC’s corporate interests and each of the sponsored drilling partnerships changed on a pro-rata basis. Effective September 30, 2008, PDC changed the allocation procedure whereby the allocation of derivative positions, between PDC and each partnership was set at a fixed quantity. Existing positions are allocated based on fixed quantities for each position and new positions will have specific designations relative to the applicable partnership.

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Notes to Financial Statements

As of December 31, 2009 and 2008, the Partnership’s derivative instruments were comprised of commodity collars and fixed price swaps and basis protection swaps.

Collars contain a fixed floor price (put) and ceiling price (call). If the index 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 index price from the counterparty. If the index 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 index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty.

At December 31, 2009 and 2008, the Partnership had the following asset and liability positions related to its open commodity-based derivative instruments for a portion of the Partnership’s natural gas and oil production.

	December 31,
	2009			2008

Derivative net assets (liabilities)
Oil and gas sales activities:
Fixed-price natural gas swaps	$	102,121		$	122,168
Natural gas collars		26,312			131,632
Natural gas basis protection swaps		(274,878	)		(27,151	)
Fixed-price oil swaps		9,974			237,820

Estimated net fair value of derivative instruments	$	(136,471	)	$	464,469

At December 31, 2009 and 2008, the maximum term for the derivative positions listed above is 48 months and 60 months, respectively.

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Notes to Financial Statements

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

			December 31,
Derivative instruments not designated as hedge (1):		Balance Sheet Line Item	2009			2008

Derivative Assets:
	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	94,751		$	345,160

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		76,808			146,461

Total Derivative Assets				171,559			491,621


Derivative Liabilities:
	Current
	Commodity contracts	Due to Managing General Partner-derivatives		(5,393	)		-

	Basis protection contracts	Due to Managing General Partner-derivatives		(68,156	)		-

	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(27,759	)		-

	Basis protection contracts	Due to Managing General Partner-derivatives		(206,722	)		(27,152	)


Total Derivative Liabilities				(308,030	)		(27,152	)

Net fair value of derivative instruments - (liability) asset			$	(136,471	)	$	464,469

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

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the years indicated.

	Year Ended December 31,
	2009									2008
Statement of operations line item	Reclassification of Realized Losses (Gains) 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 For the Current Period		Total

Commodity price risk management, net
Realized gains (losses)	$	345,147		$	40,813		$	385,960		$	(40,026	)	$	72,231	$	32,205
Unrealized (losses) gains		(345,147	)		(255,793	)		(600,940	)		40,026			464,588		504,614
Total commodity price risk management (loss) gain, net	$	-		$	(214,980	)	$	(214,980	)	$	-		$	536,819	$	536,819

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Notes to Financial Statements

Note 6 - Partners’ Equity and Cash Distributions

Partners’ Equity

A Limited Partner unit represents the individual interest of an individual investor partner in the Partnership. No public market exists or will develop for the units. While units of the Partnership are transferable, assignability of the units is limited, requiring the consent of the Managing General Partner. Further, individual investor partners may request that the Managing General Partner repurchase units pursuant to the Unit Repurchase Program.

Allocation of Partners’ Interest

The table below presents the participation of the Investor Partners and the Managing General Partner in the revenues and costs of the Partnership.

	Investor Partners			Managing General Partner
Partnership Revenue:
Natural gas and oil sales		80	%		20	%
Preferred cash distribution (a)		100	%		0	%
Commodity price risk management gain (loss)		80	%		20	%
Sale of productive properties		80	%		20	%
Sale of equipment		0	%		100	%
Interest income		80	%		20	%

Partnership Operating Costs and Expenses:
Natural gas and oil production and well operations costs (b)		80	%		20	%
Depreciation, depletion and amortization expense		80	%		20	%
Accretion of asset retirement obligations		80	%		20	%
Direct costs - general and administrative (c)		80	%		20	%

(a)

To the extent that Investor Partners receive preferred cash distributions, the allocations for Investor Partners will be increased accordingly and the allocation for the Managing General Partner will likewise be decreased. See Performance Standard Obligation of Managing General Partner below.

(b)

Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.

(c)

The Managing General Partner receives monthly reimbursement from the Partnership for direct costs – general and administrative incurred by the Managing General Partner on behalf of the Partnership.

Performance Standard Obligation of Managing General Partner

The Agreement provides for the enhancement of investor cash distributions if the Partnership does not meet a performance standard defined in the Agreement during the first 10 years of operations beginning 6 months after the funding of the Partnership. In general, if the average annual rate of return to the Investor Partners is less than 12.5% of their subscriptions, the allocation rate of cash distributions to Investor Partners will increase up to one-half of the Managing General Partner’s interest until the average annual rate increases to 12.5%, with a corresponding decrease to the Managing General Partner. The 12.5% rate of return is calculated by including the estimated benefit of a 25% income tax savings on the investment in the first year in addition to the cash distributions made to the Investor Partners as a percentage of the investment, divided by the number of years since the closing of the Partnership less six months. For the years ended December 31, 2009 and 2008, no obligation of the Managing General Partner arose under this provision.

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PDC 2003-A LIMITED PARTNERSHIP

Notes to Financial Statements

Unit Repurchase Provisions

Investor Partners may request that the Managing General Partner repurchase units at any time beginning with the third anniversary of the first cash distribution of the Partnership. The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating to 10% of the initial subscriptions, if requested by an individual investor partner, subject to PDC’s financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the Partnership to be treated as a “publically traded partnership” or result in the termination of the Partnership for federal income tax purposes. Repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis.

Cash Distributions

The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly. The Managing General Partner determines and distributes cash on a monthly basis, if funds are available for distribution. The Managing General Partner makes cash distributions of 80% to the Investor Partners and 20% to the Managing General Partner. Cash distributions began in November 2003. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:

	Year Ended December 31,
	2009		2008

Cash distributions	$	881,248	$	976,387

Distributions to Partners in 2009 were impacted by 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 $0.5 million. 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. In addition, the Partnership’s payment to the Managing General Partner for royalty settlement costs of approximately $0.1 million decreased distributions during the period. Both amounts had been previously accrued by the Partnership in “Due from (to) Managing General Partner – other, net.”

Note 7 – Concentration of Credit Risk

Major Customers. The following table presents the individual customers constituting 10% or more of the Partnership’s natural gas and oil sales, for the periods indicated:

	Year ended December 31,
Major Customer	2009			2008
DCP Midstream LP (“DCP”)		12	%		15	%
Teppco Crude Oil, LP (“Teppco”)		9	%		42	%
Williams Production RMT (“Williams”),		36	%		43	%
Suncor Energy (USA) Inc. (“Suncor”)		43	%		−

Concentration of Credit Risk. A significant component of the Partnership’s future liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Partnership to the risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to its derivative contracts. The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties default, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. The Managing General Partner has determined based on this evaluation, that the impact of counterparty nonperformance on the fair value of the Partnership’s derivative instruments is not material. For the years ended December 31, 2009 and 2008, no valuation allowance was recorded. 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.

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PDC 2003-A LIMITED PARTNERSHIP

Notes to Financial Statements

Note 8 - Asset Retirement Obligations

The following table presents the changes in the carrying amount of asset retirement obligations associated with the Partnership’s working interest in natural gas and oil properties.

	Year Ended December 31,
	2009		2008

Balance at beginning of year	$	83,859	$	79,299
Revisions in estimated cash flows		25,739		-
Accretion expense		2,073		4,560
Balance at end of year	$	111,671	$	83,859

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. The revision in estimated cash flows is due to a change in the estimated cost to plug based on recent plugging activities in the Partnership’s fields.

Note 9 - Commitments and Contingencies

Royalty Owner Class Action. On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”). The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by the Managing General Partner pursuant to leases. The Managing General Partner moved the case to Federal Court on June 28, 2007. On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership. Although the Partnership was not named as a party in the suit, the lawsuit states that this action relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s wells in the Wattenberg field. For information regarding the number of Partnership wells located in this field, see Supplemental Natural Gas and Oil Information – Unaudited, Costs Incurred in Natural Gas and Oil Property Development Activities, which follows. The portion of the settlement relating to the Partnership’s wells for all periods through December 31, 2009 that has been expensed by the Partnership is approximately $84,000 including associated legal costs of approximately $7,000. This entire settlement of $76,940 was deposited by the Managing General Partner into an escrow account on November 3, 2008. Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008. The final settlement was approved by the court on April 7, 2009. Settlement distribution checks were mailed in July 2009. During September 2009, the Partnership’s share of settlement costs were paid by the Partnership and related required judicial action from the settlement of the suit was implemented in this distribution.

Stormwater Permit. 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 (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance Basin of Colorado. Operating expenses, including amounts arising from this notice, if any, are allocated among the users of the road based upon their respective usage. For information regarding the number of Partnership wells located in this field, see Supplemental Natural Gas and Oil Information – Unaudited, Costs Incurred in Natural Gas and Oil Property Development Activities, which follows. 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 were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Managing General Partner entered negotiations with the CDPHE regarding this notice and continues to work to bring this matter to closure. Given the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict the ultimate outcome of this administrative action at this time and therefore no amounts have been recorded on the Partnership’s financial records. The Partnership has determined that any impact of the resolution of this matter will be immaterial.

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PDC 2003-A LIMITED PARTNERSHIP

Notes to Financial Statements

Derivative Contracts. The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and oil. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations by utilizing derivative instruments. Should the counterparties to the Managing General Partner’s derivative instruments not perform, the Partnership’s exposure to market fluctuations in commodity prices would increase significantly. The Managing General Partner and the Partnership have had no counterparty defaults.

F-26

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PDC 2003-A LIMITED PARTNERSHIP

Supplemental Natural Gas and Oil Information - Unaudited

Capitalized Costs and Costs Incurred in Natural Gas and Oil Property Development Activities

Natural gas and oil development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip developmental wells, to perform recompletions and to provide facilities to extract, treat, gather and store natural gas and oil.

The Partnership is engaged solely in natural gas and oil activities, all of which are located in the continental United States. Drilling operations began upon funding in April 2003 and all funds were advanced to the Managing General Partner as of December 31, 2003, for all planned drilling and completion activities. The Partnership owns an undivided working interest in 25 gross (12.3 net) natural gas and oil wells. The Partnership owns 22 wells located in the Wattenberg Field within the Denver-Julesburg (“DJ”) Basin, north and east of Denver, Colorado and three wells located in the Grand Valley Field within the Piceance Basin, situated near the western border of Colorado.

Aggregate capitalized costs related to natural gas and oil development and production activities with applicable accumulated DD&A are presented below:

	As of December 31,
	2009			2008

Leasehold costs	$	225,934		$	225,934
Development costs		9,135,219			9,083,698
Natural gas and oil properties, successful efforts method, at cost		9,361,153			9,309,632
Less: Accumulated depreciation, depletion and amortization		(5,344,051	)		(4,664,290	)
Natural gas and oil properties, net	$	4,017,102		$	4,645,342

Included in “Development Costs” are the estimated costs associated with the Partnership’s asset retirement obligations discussed in Note 8, Asset Retirement Obligations.

Net Proved Natural Gas and Oil Reserves

The Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. (Ryder Scott), to estimate the Partnership’s 2009 and 2008 natural gas and oil reserves. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC that were in effect during the each of the years 2009 and 2008, since the SEC’s Modernization of Oil and Gas Reporting final rule, adopted by the Partnership as of December 31, 2009, prohibited retroactive application of the new oil and gas industry disclosure standards. For more information regarding the SEC’s Modernization of Oil and Gas Reporting and the major provisions that impacted both the determination of and disclosures for the Partnership’s natural gas and oil reserves when adopted as of December 31, 2009, see Note 2. Summary of Significant Accounting Policies−Recently Issued Accounting Standards to the Partnership’s financial statements accompanying this Annual Report.

Proved reserve estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. The Partnership’s net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are those natural gas and oil quantities expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for recompletion.

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PDC 2003-A LIMITED PARTNERSHIP

Supplemental Natural Gas and Oil Information - Unaudited

The Partnership’s proved undeveloped reserves relate to future well recompletions in the Codell formation of the Wattenberg Field. These recompletions, which are expected to start in 2011 or later under the Well Recompletion Plan, generally occur five to ten years after initial well drilling. Funding for these recompletions are expected to be provided by withholding distributions from investors beginning in October 2010. Currently, the Partnership expects recompletion activities to be completed through approximately 2014. The time frame of recompletion activity is impacted by individual well decline curves as well on the plan to maximize the financial impact of the recompletion.

The prices used to estimate the Partnership’s reserves, by commodity, are presented below.

	Price
	Oil (per Bbl)		Gas (per Mcf)
2009	$	54.96	$	3.32
2008		38.37		4.78

The Partnership’s estimated 2009 reserve volumes below were based on 12-month average prices. For 2008, the Partnership used the year-end spot price. The following table presents changes in estimated quantities of the Partnership’s natural gas and oil reserves, all of which are located within the U. S.

	Gas			Oil			Total
	(MMcf)			(MBbl)			(MMcfe)
Proved Reserves:

Proved reserves, January 1, 2008		1,949			133			2,747
Revisions of previous estimates		(1	)		21			125
Production		(108	)		(5	)		(138	)
Proved reserves, December 31, 2008		1,840			149			2,734

Revisions of previous estimates		(148	)		3			(130	)
Production		(110	)		(6	)		(146	)
Proved reserves, December 31, 2009		1,582			146			2,458

Proved Developed Reserves, as of:

December 31, 2007		1,524			60			1,884
December 31, 2008		1,019			25			1,169
December 31, 2009		1,040			42			1,292

F-28

Index

PDC 2003-A LIMITED PARTNERSHIP

Supplemental Natural Gas and Oil Information - Unaudited

Definitions used throughout Supplemental Natural Gas and Oil Information - Unaudited:

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

MBbl – One thousand barrels

Mcf – One thousand cubic feet

Mcfe – One thousand cubic feet of gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content

MMcf – One million cubic feet

MMcfe – One million cubic feet of gas equivalents

At December 31, 2009, the Partnership’s estimated proved natural gas and oil reserves experienced a net upward revision of previous estimates of 3 MBbls of oil and net downward revision of previous estimates of 148 MMcfs of natural gas. These revisions are the result of revisions to proved developed producing reserves that includes increases of approximately 23 MBbls of oil and 131 MMcfs of natural gas, respectively, in addition to a downward revision of proved undeveloped reserves amounting to approximately 20 MBbls of oil and 279 MMcfs of natural gas, respectively. The upward revision to proved developed producing reserves was primarily due to an increase in performance projections primarily in the Wattenberg Field’s wells accompanied by increased oil pricing. The downward revision to proved undeveloped natural gas and oil reserves was primarily due to reduced economics resulting from significantly lower twelve-month average natural gas prices, partially offset by higher oil prices. There were no proved undeveloped reserves developed in 2009 or 2008. These changes in these reserves were due to changes in prices used to value reserves.

At December 31, 2008, the Partnership’s estimated proved natural gas and oil reserves experienced a net downward revision of previous estimates of 1 MBbl of oil and net upward revision of previous estimates of 21 MMcfs of natural gas. This net revision is the result of a downward revision of proved developed producing reserves amounting to approximately 30 MBbls of oil and 397 MMcfs of natural gas, respectively, offset by an upward revision of proved undeveloped reserves amounting to approximately 51 MBbls of oil and 396 MMcfs of natural gas, respectively. The downward revision to proved developed producing reserves was primarily due to the Partnership’s wells’ reduced productive lives resulting from significantly lower year-end natural gas and oil prices and higher per-well operating costs at December 31, 2008. The upward revision to proved undeveloped reserves was due primarily to an increase in performance projections based upon a detailed analysis of the results of the Codell zone refractures in the Wattenberg Field performed by PDC, the Managing General Partner, over the last several years.

F-29

Index

PDC 2003-A LIMITED PARTNERSHIP

Condensed Quarterly Balance Sheets

(Unaudited)

	As of
	March 31,			June 30,			September 30,			December 31,
Assets	2009			2009			2009			2009*

Current assets:
Cash and cash equivalents	$	37,125		$	37,138		$	157		$	133
Accounts receivable		25,307			47,209			74,077			64,246
Oil inventory		13,113			13,000			10,810			11,442
Due from Managing General Partner-derivatives		391,216			253,877			176,737			94,751
Due from Managing General Partner-other, net		156,108			19,417			-			8,289
Total current assets		622,869			370,641			261,781			178,861


Natural gas and oil properties, successful efforts method, at cost		9,330,174			9,333,751			9,335,284			9,361,153
Less: Accumulated depreciation, depletion and amortization		(4,854,949	)		(5,050,737	)		(5,240,942	)		(5,344,051	)
Natural gas and oil properties, net		4,475,225			4,283,014			4,094,342			4,017,102

Due from Managing General Partner-derivatives		80,888			30,633			15,654			76,808
Other assets		14,414			16,294			17,429			19,132
Total noncurrent assets		4,570,527			4,329,941			4,127,425			4,113,042


Total Assets	$	5,193,396		$	4,700,582		$	4,389,206		$	4,291,903


Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	7,225		$	7,760		$	5,857		$	7,588
Due to Managing General Partner-derivatives		-			18,559			63,045			73,549
Due to Managing General Partner-other		-			-			122,534			-
Total current liabilities		7,225			26,319			191,436			81,137

Due to Managing General Partner-derivatives		149,864			183,497			211,061			234,481
Asset retirement obligations		85,064			86,269			87,474			111,671
Total liabilities		242,153			296,085			489,971			427,289

Partners' equity:
Managing General Partner		991,542			882,192			781,140			774,216
Limited Partners - 424.15 units issued and outstanding		3,959,701			3,522,305			3,118,095			3,090,398
Total Partners' equity		4,951,243			4,404,497			3,899,235			3,864,614

Total Liabilities and Partners' Equity	$	5,193,396		$	4,700,582		$	4,389,206		$	4,291,903

*Derived from audited December 31, 2009 balance sheet contained in the Partnership’s accompanying financial statements for the year ended December 31, 2009, included in this report.

See accompanying notes to unaudited condensed quarterly financial statements.

F-30

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PDC 2003-A LIMITED PARTNERSHIP

Condensed Quarterly Balance Sheets

(Unaudited)

	As of
	March 31,			June 30,			September 30,			December 31,
Assets	2008			2008			2008			2008*

Current assets:
Cash and cash equivalents	$	34,240		$	35,157		$	36,454		$	36,809
Accounts receivable		142,970			127,373			97,336			41,288
Oil inventory		16,258			18,026			17,150			20,380
Due from Managing General Partner-derivatives		8,090			4,018			146,213			345,160
Due from Managing General Partner-other, net		370,742			297,379			307,679			198,081
Total current assets		572,300			481,953			604,832			641,718


Natural gas and oil properties, successful efforts method, at cost		9,293,583			9,305,470			9,306,539			9,309,632
Less: Accumulated depreciation, depletion and amortization		(4,319,505	)		(4,413,249	)		(4,509,990	)		(4,664,290	)
Natural gas and oil properties, net		4,974,078			4,892,221			4,796,549			4,645,342

Due from Managing General Partner-derivatives		11,889			11,841			68,290			146,461
Due from Managing General Partner-other		41,011			48,398			55,168			-
Other assets		6,893			8,774			10,654			12,534
Total noncurrent assets		5,033,871			4,961,234			4,930,661			4,804,337


Total Assets	$	5,606,171		$	5,443,187		$	5,535,493		$	5,446,055


Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	30,846		$	32,252		$	29,679		$	12,326
Due to Managing General Partner-derivatives		231,934			499,018			48,880			-
Total current liabilities		262,780			531,270			78,559			12,326

Due to Managing General Partner-derivatives		56,513			316,952			52,159			27,152
Asset retirement obligations		80,439			81,579			82,719			83,859
Total liabilities		399,732			929,801			213,437			123,337

Partners' equity:
Managing General Partner		1,042,579			903,969			1,065,703			1,065,836
Limited Partners - 424.15 units issued and outstanding		4,163,860			3,609,417			4,256,353			4,256,882
Total Partners' equity		5,206,439			4,513,386			5,322,056			5,322,718

Total Liabilities and Partners' Equity	$	5,606,171		$	5,443,187		$	5,535,493		$	5,446,055

*Derived from audited December 31, 2008 balance sheet contained in the Partnership’s accompanying financial statements for the year ended December 31, 2008, included in this report.

See accompanying notes to unaudited condensed quarterly financial statements.

F-31

Index

PDC 2003-A LIMITED PARTNERSHIP

Condensed Quarterly Statement of Operations

(Unaudited)

	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	2009			2009			2009			2009
Revenues:
Natural gas and oil sales	$	144,954		$	155,517		$	167,774		$	185,980
Commodity price risk management (loss) gain, net		(4,008	)		(147,631	)		(86,186	)		22,845
Total revenues		140,946			7,886			81,588			208,825

Operating costs and expenses:
Natural gas and oil production costs		72,744			69,931			69,170			56,013
Direct costs - general and administrative		21,197			5,457			38,142			11,951
Depreciation, depletion and amortization		190,659			195,788			190,205			103,109
Accretion of asset retirement obligations		1,205			1,205			1,205			(1,542	)
Total operating costs and expenses		285,805			272,381			298,722			169,531

(Loss) income from operations		(144,859	)		(264,495	)		(217,134	)		39,294

Interest expense		-			-			(2,535	)		-
Interest income		4,117			4,057			4,699			-

Net (loss) income	$	(140,742	)	$	(260,438	)	$	(214,970	)	$	39,294

Net (loss) income allocated to partners	$	(140,742	)	$	(260,438	)	$	(214,970	)	$	39,294
Less: Managing General Partner interest in net (loss) income		(28,148	)		(52,088	)		(42,994	)		7,859
Net (loss) income allocated to Investor Partners	$	(112,594	)	$	(208,350	)	$	(171,976	)	$	31,435

Net (loss) income per Investor Partner unit	$	(265	)	$	(491	)	$	(405	)	$	74

Investor Partner units outstanding		424.15			424.15			424.15			424.15

See accompanying notes to unaudited condensed quarterly financial statements

F-32

Index

PDC 2003-A LIMITED PARTNERSHIP

Condensed Quarterly Statements of Operations

(Unaudited)

	Quarter Ended
	March 31,			June 30,			September 30,		December 31,
	2008			2008			2008		2008
Revenues:
Natural gas and oil sales	$	354,118		$	373,136		$	341,950	$	143,038
Commodity price risk management (loss) gain, net		(242,576	)		(601,446	)		918,898		461,943
Total revenues		111,542			(228,310	)		1,260,848		604,981

Operating costs and expenses:
Natural gas and oil production costs		102,464			90,109			95,504		171,204
Direct costs - general and administrative		8,336			9,906			5,802		15,287
Depreciation, depletion and amortization		112,998			93,744			96,741		154,300
Accretion of asset retirement obligations		1,140			1,140			1,140		1,140
Total operating costs and expenses		224,938			194,899			199,187		341,931

(Loss) income from operations		(113,396	)		(423,209	)		1,061,661		263,050

Interest income		5,773			5,468			5,335		5,267

Net (loss) income	$	(107,623	)	$	(417,741	)	$	1,066,996	$	268,317

Net (loss) income allocated to partners	$	(107,623	)	$	(417,741	)	$	1,066,996	$	268,317
Less: Managing General Partner interest in net (loss) income		(21,525	)		(83,548	)		213,399		53,664
Net (loss) income allocated to Investor Partners	$	(86,098	)	$	(334,193	)	$	853,597	$	214,653

Net (loss) income per Investor Partner unit	$	(203	)	$	(788	)	$	2,012	$	506

Investor Partner units outstanding		424.15			424.15			424.15		424.15

See accompanying notes to unaudited condensed quarterly financial statements.

F-33

Index

PDC 2003-A LIMITED PARTNERSHIP

Condensed Interim Statements of Cash Flows

(Unaudited)

	Three Months Ended March 31, 2009			Six Months Ended June 30, 2009			Nine Months Ended September 30, 2009
Cash flows from operating activities:
Net loss	$	(140,742	)	$	(401,180	)	$	(616,150	)
Adjustments to net loss to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		190,659			386,447			576,652
Accretion of asset retirement obligations		1,205			2,410			3,615
Unrealized loss on derivative transactions		142,229			382,015			546,184
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		15,981			(5,921	)		(32,789	)
Decrease in oil inventory		7,267			7,380			9,570
Increase in other assets		(1,880	)		(3,760	)		(4,895	)
Decrease in accounts payable and accrued expenses		(5,101	)		(4,566	)		(6,469	)
Decrease in Due from Managing General Partner - other, net		41,973			178,664			320,615
Net cash provided by operating activities		251,591			541,489			796,333

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(20,542	)		(24,119	)		(25,652	)
Net cash used in investing activities		(20,542	)		(24,119	)		(25,652	)

Cash flows from financing activities:
Distributions to Partners		(230,733	)		(517,041	)		(807,333	)
Net cash used in financing activities		(230,733	)		(517,041	)		(807,333	)

Net increase in cash and cash equivalents		316			329			(36,652	)
Cash and cash equivalents, beginning of year		36,809			36,809			36,809
Cash and cash equivalents, end of period	$	37,125		$	37,138		$	157

Cash payments for:
Interest	$	-		$	-		$	2,535

See accompanying notes to unaudited condensed quarterly financial statements.

F-34

Index

PDC 2003-A LIMITED PARTNERSHIP

Condensed Interim Statements of Cash Flows

(Unaudited)

	Three			Six			Nine
	Months Ended			Months Ended			Months Ended
	March 31,			June 30,			September 30,
	2008			2008			2008
Cash flows from operating activities:
Net (loss) income	$	(107,623	)	$	(525,364	)	$	541,632
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		112,998			206,742			303,483
Accretion of asset retirement obligations		1,140			2,280			3,420
Unrealized loss (gain) on derivative transactions		228,323			759,966			(153,609	)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		(31,686	)		(16,089	)		13,948
Increase in oil inventory		(16,258	)		(18,026	)		(17,150	)
Increase in other assets		(1,880	)		(3,761	)		(5,641	)
Increase in accounts payable and accrued expenses		16,799			18,205			15,632
(Increase) decrease in Due from Managing General Partner - other, net		(4,771	)		61,205			44,135
Net cash provided by operating activities		197,042			485,158			745,850

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(20,848	)		(32,735	)		(33,804	)
Net cash used in investing activities		(20,848	)		(32,735	)		(33,804	)

Cash flows from financing activities:
Distributions to Partners		(175,094	)		(450,406	)		(708,732	)
Net cash used in financing activities		(175,094	)		(450,406	)		(708,732	)

Net increase in cash and cash equivalents		1,100			2,017			3,314
Cash and cash equivalents, beginning of year		33,140			33,140			33,140
Cash and cash equivalents, end of period	$	34,240		$	35,157		$	36,454

See accompanying notes to unaudited condensed quarterly financial statements

F-35

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Unaudited Condensed Quarterly Financial Statements

Note 1 - Basis of Presentation

The PDC 2003-A Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership on June 3, 2002, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and oil properties and commenced business operations with its funding on April 30, 2003, upon completion of its sale of Partnership units.

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

Note 2 - Transactions with Managing General Partner and Affiliates

The following table presents 2009 and 2008 transactions with the Managing General Partner reflected in the balance sheet caption “Due from Managing General Partner – other, net,” which remain undistributed or unsettled with the Partnership’s investors, as of end of the three month periods described below:

	As of
	March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009

Natural gas and oil sales revenues collected from the Partnership's third-party customers	$	119,646		$	94,474		$	43,695		$	71,800
Commodity Price Risk Management, Realized Gains		138,219			92,153			50,576			58,656
Other (1)		(101,757	)		(167,210	)		(216,805	)		(122,167	)
Total Due from Managing General Partner-other, net	$	156,108		$	19,417		$	(122,534	)	$	8,289

	As of
	March 31, 2008			June 30, 2008			September 30, 2008		December 31, 2008

Natural gas and oil sales revenues collected from the Partnership's third-party customers	$	211,147		$	245,763		$	244,614	$	101,750
Commodity Price Risk Management, Realized (Losses) Gains		(14,253	)		(69,803	)		5,323		110,938
Other (1)		214,859			169,817			112,910		(14,607	)
Total Due from Managing General Partner-other, net	$	411,753		$	345,777		$	362,847	$	198,081

(1)

F-36

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Unaudited Condensed Quarterly Financial Statements

Additionally, certain amounts representing royalties on Partnership production paid in September 2009 were recorded by the Partnership as liabilities in the account “Due from (to) Managing General Partner-other, net.” These amounts, which totaled approximately $84,000 including legal fees of approximately $7,000, represented the Partnership’s share of the court approved royalty litigation payment and settlement, more fully described in Note 6, Commitments and Contingencies. During September 2009, all settlement costs related to this litigation were paid by the Partnership, to the Managing General Partner.

The following table presents transactions with the Managing General Partner and its affiliates during the quarters ended March 31, June 30, September 30 and December 31, for the years 2009 and 2008. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Production and operating costs” on the Statements of Operations.

	Quarter Ended
	March 31, 2009		June 30, 2009		September 30, 2009		December 31, 2009
Transaction
Well operations and maintenance	$	57,516	$	56,074	$	53,979	$	46,338
Gathering, compression and processing fees		5,821		5,291		5,673		6,187
Direct costs- general and administrative		21,197		5,457		38,142		11,951
Cash distributions*		53,582		66,994		68,098		17,340

	Quarter Ended
	March 31, 2008		June 30, 2008		September 30, 2008		December 31, 2008
Transaction
Well operations and maintenance	$	72,656	$	60,497	$	67,949	$	157,141
Gathering, compression and processing fees		5,973		4,747		4,646		4,569
Direct costs- general and administrative		8,336		9,906		5,802		15,287
Cash distributions*		38,598		61,026		59,111		62,157

*Cash distributions started in November 2003. Cash distributions presented above represent amounts paid to PDC for its Managing General Partner’s 20% ownership share in the Partnership and include equity cash distributions on Investor Partner limited partnership units repurchased by PDC. The following table presents equity cash distributions for the three month periods identified, associated to these limited partnership units repurchases by PDC.

Three months ended	2009		2008

March 31	$	7,436	$	3,579
June 30		9,732		5,964
September 30		10,040		7,446
December 31		2,557		8,626

Note 3 - Fair Value Measurements

F-37

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Unaudited Condensed Quarterly Financial Statements

Level 3 – Unobservable inputs for the asset or 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 derivative instruments for Colorado Interstate Gas, or CIG, based fixed-price natural gas swaps, collars, oil swaps, and natural gas basis protection swaps.

F-38

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Unaudited Condensed Quarterly Financial Statements

The following table presents, by hierarchy level, the Partnership’s 2009 and 2008 derivative financial instruments, including both current and non-current portions, measured at fair value for the three months ended March 31, June 30, September 30 and December 31, respectively:

	Quarter ended
	March 31, 2009									March 31, 2008
	Level 1			Level 3			Total			Level 1		Level 3			Total
Assets:.
Commodity based derivatives	$	-		$	472,104		$	472,104		$	-	$	19,979		$	19,979
Basis protection derivative contracts		-			-			-			-		-			-
Total assets		-			472,104			472,104			-		19,979			19,979

Liabilities:
Commodity based derivatives		(9,032	)		(258	)		(9,290	)		-		(288,447	)		(288,447	)
Basis protection derivative contracts		-			(140,574	)		(140,574	)		-		-			-
Total liabilities		(9,032	)		(140,832	)		(149,864	)		-		(288,447	)		(288,447	)

Net fair value of derivative instruments	$	(9,032	)	$	331,272		$	322,240		$	-	$	(268,468	)	$	(268,468	)

	Quarter ended
	June 30, 2009									June 30, 2008
	Level 1			Level 3			Total			Level 1		Level 3			Total
Assets:.
Commodity based derivatives	$	33		$	284,477		$	284,510		$	-	$	15,859		$	15,859
Basis protection derivative contracts		-			-			-			-		-			-
Total assets		33			284,477			284,510			-		15,859			15,859

Liabilities:
Commodity based derivatives		(16,840	)		(604	)		(17,444	)		-		(815,970	)		(815,970	)
Basis protection derivative contracts		-			(184,612	)		(184,612	)		-		-			-
Total liabilities		(16,840	)		(185,216	)		(202,056	)		-		(815,970	)		(815,970	)

Net fair value of derivative instruments	$	(16,807	)	$	99,261		$	82,454		$	-	$	(800,111	)	$	(800,111	)

	Quarter ended
	September 30, 2009									September 30, 2008
	Level 1			Level 3			Total			Level 1		Level 3			Total
Assets:.
Commodity based derivatives	$	541		$	191,850		$	192,391		$	-	$	214,503		$	214,503
Basis protection derivative contracts		-			-			-			-		-			-
Total assets		541			191,850			192,391			-		214,503			214,503

Liabilities:
Commodity based derivatives		(21,559	)		(15,080	)		(36,639	)		-		(101,039	)		(101,039	)
Basis protection derivative contracts		-			(237,467	)		(237,467	)		-		-			-
Total liabilities		(21,559	)		(252,547	)		(274,106	)		-		(101,039	)		(101,039	)

Net fair value of derivative instruments	$	(21,018	)	$	(60,697	)	$	(81,715	)	$	-	$	113,464		$	113,464

	Quarter ended
	December 31, 2009									December 31, 2008
	Level 1			Level 3			Total			Level 1		Level 3			Total
Assets:.
Commodity based derivatives	$	77,667		$	93,892		$	171,559		$	-	$	491,621		$	491,621
Basis protection derivative contracts		-			-			-			-		-			-
Total assets		77,667			93,892			171,559			-		491,621			491,621

Liabilities:
Commodity based derivatives		(5,255	)		(27,897	)		(33,152	)		-		-			-
Basis protection derivative contracts		-			(274,878	)		(274,878	)		-		(27,152	)		(27,152	)
Total liabilities		(5,255	)		(302,775	)		(308,030	)		-		(27,152	)		(27,152	)

Net fair value of derivative instruments	$	72,412		$	(208,883	)	$	(136,471	)	$	-	$	464,469		$	464,469

F-39

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Unaudited Condensed Quarterly Financial Statements

The following table presents the changes of the Partnership’s 2009 and 2008 Level 3 derivative financial instruments measured on a recurring basis as of the end of the three month periods described below.

	Three months ended
	March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009
Fair value, net asset (liability) beginning of period	$	464,469		$	331,272		$	99,261		$	(60,697	)
Changes in fair value included in statement of operations line item:
Commodity price risk management gain (loss), net		5,024			(139,856	)		(81,975	)		(70,585	)
Settlements		(138,221	)		(92,155	)		(77,983	)		(77,601	)
Fair value, net asset (liability) end of period	$	331,272		$	99,261		$	(60,697	)	$	(208,883	)

Change in unrealized gains (losses) relating to assets (liabilities) still held as of end of period included in statement of operations line item:
Commodity price risk management loss, net	$	(17,519	)	$	(155,574	)	$	(110,480	)	$	(17,925	)


	Three months ended
	March 31, 2008			June 30, 2008			September 30, 2008			December 31, 2008
Fair value, net (liability) asset beginning of period	$	(40,145	)	$	(268,468	)	$	(800,111	)	$	113,464
Changes in fair value included in statement of operations line item:
Commodity price risk management (loss) gain, net		(242,576	)		(601,446	)		918,898			461,943
Settlements		14,253			69,803			(5,323	)		(110,938	)
Fair value, net (liability) asset end of period	$	(268,468	)	$	(800,111	)	$	113,464		$	464,469

Change in unrealized gains (losses) relating to assets (liabilities) still held as of end of period included in statement of operations line item:
Commodity price risk management gain (loss), net	$	-		$	-		$	-		$	-

See Note 4, Derivative Financial Instruments, for additional disclosure related to the Partnership’s derivative financial instruments.

Note 4 - Derivative Financial Instruments

As of December 31, 2009, the Partnership’s derivative instruments were comprised of commodity collars and fixed price swaps and basis protection swaps.

F-40

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Unaudited Condensed Quarterly Financial Statements

During 2009 and 2008, at the end of the three month periods noted below, the Partnership had the following asset and liability positions related to its open commodity-based derivative instruments for a portion of the Partnership’s natural gas and oil production.

	As of
	March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009

Derivative net assets (liabilities)
Oil and gas sales activities:
Fixed-price natural gas swaps	$	51,887		$	39,774		$	28,792		$	102,121
Natural gas collars		201,958			129,304			54,300			26,312
Natural gas basis protection swaps		(140,574	)		(184,612	)		(237,467	)		(274,878	)
Fixed-price oil swaps		208,969			97,988			72,660			9,974

Estimated net fair value of derivative instruments	$	322,240		$	82,454		$	(81,715	)	$	(136,471	)

	As of
	March 31, 2008			June 30, 2008			September 30, 2008			December 31, 2008

Derivative net assets (liabilities)
Oil and gas sales activities:
Fixed-price natural gas swaps	$	(145,189	)	$	(208,566	)	$	127,864		$	122,168
Natural gas collars		(15,924	)		(10,428	)		74,273			131,632
Natural gas basis protection swaps		-			-			-			(27,151	)
Oil collars		(25,301	)		-			-			-
Fixed-price oil swaps		(82,054	)		(581,117	)		(88,673	)		237,820

Estimated net fair value of derivative instruments	$	(268,468	)	$	(800,111	)	$	113,464		$	464,469

At December 31, 2009 and 2008, the maximum term for the derivative positions listed above is 48 months and 60 months, respectively.

F-41

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Unaudited Condensed Quarterly Financial Statements

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

			As of
Derivative instruments not designated as hedge (1):		Balance Sheet Line Item	March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009

Derivative Assets:
	Current
	Commodity contracts	Due from Managing General Partner - derivatives	$	391,216		$	253,877		$	176,737		$	94,751

	Non Current
	Commodity contracts	Due from Managing General Partner - derivatives		80,888			30,633			15,654			76,808

Total Derivative Assets				472,104			284,510			192,391			171,559


Derivative Liabilities:
	Current
	Commodity contracts	Due to Managing General Partner - derivatives		-			(3,499	)		(19,231	)		(5,393	)

	Basis protection contracts	Due to Managing General Partner - derivatives		-			(15,060	)		(43,814	)		(68,156	)

	Non Current
	Commodity contracts	Due to Managing General Partner - derivatives		(9,290	)		(13,945	)		(17,407	)		(27,759	)

	Basis protection contracts	Due to Managing General Partner - derivatives		(140,574	)		(169,552	)		(193,654	)		(206,722	)


Total Derivative Liabilities				(149,864	)		(202,056	)		(274,106	)		(308,030	)

Net fair value of derivative instruments - asset (liability)			$	322,240		$	82,454		$	(81,715	)	$	(136,471	)


			As of
Derivative instruments not designated as hedge (1):		Balance Sheet Line Item	March 31, 2008			June 30, 2008			September 30, 2008			December 31, 2008

Derivative Assets:
	Current
	Commodity contracts	Due from Managing General Partner - derivatives	$	8,090		$	4,018		$	146,213		$	345,160

	Non Current
	Commodity contracts	Due from Managing General Partner - derivatives		11,889			11,841			68,290			146,461

Total Derivative Assets				19,979			15,859			214,503			491,621


Derivative Liabilities:
	Current
	Commodity contracts	Due to Managing General Partner - derivatives		(231,934	)		(499,018	)		(48,880	)		-

	Non Current
	Commodity contracts	Due to Managing General Partner - derivatives		(56,513	)		(316,952	)		(52,159	)		-

	Basis protection contracts	Due to Managing General Partner - derivatives		-			-			-			(27,152	)


Total Derivative Liabilities				(288,447	)		(815,970	)		(101,039	)		(27,152	)

Net fair value of derivative instruments - (liability) asset			$	(268,468	)	$	(800,111	)	$	113,464		$	464,469

(1)

As of December 31, 2009 and 2008, none of the Partnership’s derivative instruments were designated as hedges.

F-42

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Unaudited Condensed Quarterly Financial Statements

The following table presents the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three-months ended March 31, June 30, September 30 and December 31 for the years indicated:

	Three months ended
	March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009
Commodity price risk management, net
Realized gains (losses)
Oil	$	45,563		$	30,020		$	21,876		$	14,114
Natural Gas		92,658			62,135			56,107			63,487
Total realized gain, net		138,221			92,155			77,983			77,601

Unrealized gains (losses)
Reclassification of realized gains included in prior periods unrealized (1)		(115,421	)		(101,810	)		(77,521	)		(75,394	)
Unrealized (loss) gain for the period (1)		(26,808	)		(137,976	)		(86,648	)		20,638
Total unrealized loss, net		(142,229	)		(239,786	)		(164,169	)		(54,756	)
Commodity price risk management (loss) gain, net	$	(4,008	)	$	(147,631	)	$	(86,186	)	$	22,845


	Three months ended
	March 31, 2008			June 30, 2008			September 30, 2008			December 31, 2008
Commodity price risk management, net
Realized gains (losses)
Oil	$	(8,232	)	$	(23,783	)	$	(14,624	)	$	32,848
Natural Gas		(6,021	)		(46,020	)		19,947			78,090
Total realized (loss) gain, net		(14,253	)		(69,803	)		5,323			110,938

Unrealized gains (losses)
Reclassification of realized (gains) losses included in prior periods unrealized (1)		(19,927	)		66,483			135,095			(57,930	)
Unrealized (loss) gain for the period (1)		(208,396	)		(598,126	)		778,480			408,935
Total unrealized (loss) gain, net		(228,323	)		(531,643	)		913,575			351,005
Commodity price risk management (loss) gain, net	$	(242,576	)	$	(601,446	)	$	918,898		$	461,943

(1)

Note 5 - Capitalized Costs Relating to Natural Gas and Oil Activities

The Partnership is engaged solely in natural gas and oil activities, all of which are located in the continental United States. Drilling operations began upon funding on April 30, 2003 with advances made to the Managing General Partner for all planned drilling and completion costs for the Partnership made in December 2003. Costs capitalized for these activities are as follows:

	As of
	March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009

Leasehold costs	$	225,939		$	225,939		$	225,934		$	225,934
Development costs		9,104,235			9,107,812			9,109,350			9,135,219
Natural gas and oil properties, successful efforts method, at cost		9,330,174			9,333,751			9,335,284			9,361,153
Less: Accumulated depreciation, depletion and amortization		(4,854,949	)		(5,050,737	)		(5,240,942	)		(5,344,051	)
Natural gas and oil properties, net	$	4,475,225		$	4,283,014		$	4,094,342		$	4,017,102

	As of
	March 31, 2008			June 30, 2008			September 30, 2008			December 31, 2008

Leasehold costs	$	225,934		$	225,934		$	225,934		$	225,934
Development costs		9,067,649			9,079,536			9,080,605			9,083,698
Natural gas and oil properties, successful efforts method, at cost		9,293,583			9,305,470			9,306,539			9,309,632
Less: Accumulated depreciation, depletion and amortization		(4,319,505	)		(4,413,249	)		(4,509,990	)		(4,664,290	)
Natural gas and oil properties, net	$	4,974,078		$	4,892,221		$	4,796,549		$	4,645,342

F-43

Index

PDC 2003-A LIMITED PARTNERSHIP

Notes to Unaudited Condensed Quarterly Financial Statements

Note 6 - Commitments and Contingencies

Royalty Owner Class Action. On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”). The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by the Managing General Partner pursuant to leases. The Managing General Partner moved the case to Federal Court on June 28, 2007. On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership. Although the Partnership was not named as a party in the suit, the lawsuit states that this action relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s wells in the Wattenberg field. For information regarding the number of Partnership wells located in this field, see the preceding Supplemental Natural Gas and Oil Information – Unaudited, Costs Incurred in Natural Gas and Oil Property Development Activities. The portion of the settlement relating to the Partnership’s wells for all periods through December 31, 2009 that has been expensed by the Partnership is approximately $84,000 including associated legal costs of approximately $7,000. This entire settlement of $76,940 was deposited by the Managing General Partner into an escrow account on November 3, 2008. Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008. The final settlement was approved by the court on April 7, 2009. Settlement distribution checks were mailed in July 2009. During September 2009, the Partnership’s share of settlement costs were paid by the Partnership and related required judicial action from the settlement of the suit was implemented in this distribution.

Stormwater Permit. 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 (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are oil and gas companies operating in the Piceance Basin of Colorado. Operating expenses, including amounts arising from this notice, if any, are allocated among the users of the road based upon their respective usage. For information regarding the number of Partnership wells located in this field, see the preceding Supplemental Natural Gas and Oil Information – Unaudited, Costs Incurred in Natural Gas and Oil Property Development Activities. 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 were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Managing General Partner entered negotiations with the CDPHE regarding this notice and continues to work to bring this matter to closure. Given the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict the ultimate outcome of this administrative action at this time and therefore no amounts have been recorded on the Partnership’s financial records. The Partnership has determined that any impact of the resolution of this matter will be immaterial.

F-44

Attached files

PDC 2003-A LP Reports

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