Rockies Region 2006 Limited Partnership - FORM 10-K

Attached files

file	filename
EX-99.2 - EXHIBIT 99.2 - Rockies Region 2006 Limited Partnership	ex99_2.htm
EX-32.1 - EXHIBIT 32.1 - Rockies Region 2006 Limited Partnership	ex32_1.htm
EX-31.2 - EXHIBIT 31.2 - Rockies Region 2006 Limited Partnership	ex31_2.htm
EX-23.1 - EXHIBIT 23.1 - Rockies Region 2006 Limited Partnership	ex23_1.htm
EX-31.1 - EXHIBIT 31.1 - Rockies Region 2006 Limited Partnership	ex31_1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

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

For the fiscal year ended December 31, 2009

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

Commission File Number 000-52787

Rockies Region 2006 Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia	20-5149573
(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 £ No T

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

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 T No £

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

Indicate by check mark 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. T

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

Large accelerated filer £	Accelerated filer £

Non-accelerated filer £	Smaller reporting company T

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

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 December 31, 2009, the Partnership had 4,497.03 units of limited partnership interest and no units of additional general partnership interest outstanding.

ROCKIES REGION 2006 LIMITED PARTNERSHIP

INDEX TO REPORT ON FORM 10-K

		Page

PART I

	Special Note Regarding Forward-Looking Statements	1
Item 1	Business	2
Item 1A	Risk Factors	16
Item 1B	Unresolved Staff Comments	16
Item 2	Properties	16
Item 3	Legal Proceedings	16
Item 4	[Reserved]	16

PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6	Selected Financial Data	19
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	30
Item 8	Financial Statements and Supplementary Data	30
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	30
Item 9A(T)	Controls and Procedures	31
Item 9B	Other Information	33

PART III

Item 10	Directors, Executive Officers and Corporate Governance	33
Item 11	Executive Compensation	38
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	38
Item 13	Certain Relationships and Related Transactions, and Director Independence	38
Item 14	Principal Accountant Fees and Services	40

PART IV

Item 15	Exhibits, Financial Statement Schedules	41

Signatures		42

Financial Statements		F-1

Index

PART I

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 Rockies Region 2006 Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business, financial condition and results of operations. 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 PDC’s strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

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

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

future production and development costs;

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

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

the effect of natural gas and oil derivatives activities;

conditions in the capital markets; and

losses possible from pending or future litigation.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements made in this report 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. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

- 1 -

Index

Item 1.

Business

General Information

The Partnership is a privately subscribed West Virginia Limited Partnership which owns an undivided working interest in natural gas and oil wells located in Colorado and North Dakota from which the Partnership produces and sells natural gas and oil. The Partnership was organized and began operations in 2006 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”), who own 63% of the Partnership’s capital, or equity interests, and PDC, Managing General Partner, a Nevada Corporation, who owns the remaining 37% 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 utilized 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 September 4, 2007:

RR06LP Limited Partnership Information	Date	Number of Partners		Number of Partner Units					Equity Percentage			Amount (millions)
RR06LP Limited Partnership Information	Date	Number of Partners		Additional General Partner Units			Limited Partner Units		Equity Percentage			Amount (millions)

West Virginia Limited Partnership Formation	July 20, 2006
Limited Partnership Termination Date	December 31, 2056

Private Placement of Securities and Funding	September 7, 2006
Investor Partners (1) Unit Cost: $20,000			2,022		4,449.78			47.25		63.00	%	$	89.9
PDC, Managing General Partner										37.00	%		38.9
Total funding													128.8
Syndication costs paid to third-party brokers													(9.1	)
Management Fee Paid to PDC													(1.3	)
Net funding available for drilling activities										100.00	%	$	118.4

Conversion of additional General Partners to Limited Partners	September 4, 2007				(4,449.78	)		4,449.78
Limited Partnership Units after Conversion					-			4,497.03

(1)

The Managing General Partner repurchases 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 oil and natural gas properties until such time that a well is depleted or becomes uneconomical to produce, at which time that well will be plugged and abandoned. The Partnership’s maximum term of existence extends through December 31, 2056, 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.

Business Strategy

The primary objective of the Partnership is the profitable operation of developed Colorado and North Dakota oil and natural gas 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, oil and natural gas sales.

- 2 -

Index

Development

The Partnership’s Denver-Julesburg (“DJ”) Basin wells are situated in the Wattenberg Field, located north and east of Denver. The Codell formation, from which natural gas and oil is produced, is the primary producing zone for most of the Partnership’s 63 producing wells developed in the Wattenberg Field. In addition to the Wattenberg Field’s producing wells, one additional well (1.0 net) drilled to the Codell formation in the field was evaluated as commercially unproductive and was therefore declared to be developmental dry hole. Although the Partnership’s natural gas and oil drilling activities were principally devoted to the development of natural gas and oil resources in Codell formation currently under production, the Partnership did participate in three Wattenberg Field exploratory wells (3.0 net) drilled to the D Sand and J Sand formations, which were determined to be commercially unproductive and therefore declared to be a exploratory dry holes. An exploratory well is one which is drilled in an area where there has been no oil or natural gas production, or a well which is drilled to a previously untested or non-producing zone in an area where there are wells producing from other formations. Two of these exploratory dry holes were subsequently sold to non-affiliated third parties in 2008.

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 23 Grand Valley Field producing 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, followed by years of relatively shallow decline.

In addition to the Colorado natural gas and oil properties development, the Partnership participated in seven wells drilled in the western North Dakota portion of the Williston Basin. Three productive Bakken Shale developmental wells, which produce oil in addition to some natural gas, were drilled in the Bailey Field. In the Carter Field, the Partnership participated in one productive developmental oil well and one productive exploratory oil well, both drilled to the Nesson formation. During 2007, two exploratory wells (2.0 net) drilled to the Nesson formation, one drilled in the Coteau Field and the second drilled in the Wildcat Field, were determined to be commercially unproductive as of December 31, 2007 and therefore were declared to be exploratory dry holes.

Well recompletions in the Codell formation of Wattenberg Field wells, which may provide for additional reserve development and production, generally occur five to ten years after initial well drilling so that well resources are optimally utilized. These well recompletions would be expected to occur based on a favorable general economic environment and commodity price structure. 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 cash availability through any combination of borrowing from third parties or the retention of Partnership distributable cash flows, if needed, so that Partnership operations may fully develop the Partnership's wells; but if full development of the Partnership's wells proves commercially unsuccessful, an individual investor partner might anticipate a reduction in cash distributions.

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. On average, 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 out of future revenues earned from natural gas and oil sales, in the case of repayment of borrowing or advances, or out of funds retained by the Managing General Partner from distributable cash flows.

The Managing General Partner has developed a plan to initiate recompletion activities during 2012. This plan includes notifying investor partners that funding for these recompletions will be procured through any combination of bank borrowings or withholding of future distributable cash flows of the Partnership resulting from both current production and any increased production due to recompletion activities. The funds retained necessary for the Partnership to pay for the 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 made available to the Partnership, through these funding sources. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed. As the optimal period approaches, the Managing General Partner will re-evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion. Further-developed Partnership wells may not generate sufficient funds from production to cover revenues retained or to repay financial obligations of the Partnership for borrowed funds, plus interest. All borrowings will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for loan repayment.

- 3 -

Index

Drilling and Other Development Activities

The Partnership’s properties (the “Properties”) consist of a working interest for the well bore in each well drilled by the Partnership. The Partnership drilled 97 wells (95.7 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 August 2007 when the last of the Partnership’s 91 productive wells (89.7 net) were connected to sales and gathering lines. One Wattenberg Field Codell formation well (1.0 net) and three Wattenberg Field D Sand and J Sand formations wells (3.0 net) drilled were evaluated as commercially unproductive and were therefore declared to be developmental and exploratory dry hole(s), respectively. Additionally, the Partnership participated in two North Dakota Nesson formation exploratory wells (2.0) net, one drilled in the Coteau Field and the second drilled in the Wildcat Field, which were determined to be commercially unproductive and therefore declared to be exploratory dry holes. The 97 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 utilized. 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 is to produce and sell the oil and gas 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.

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 does not believe that any additional burdens, liens or encumbrances customary to the industry, if any, will materially interfere with the commercial use of the properties. Provisions of the Agreement generally relieve PDC from any error in judgment with respect to the waiver of title defects.

- 4 -

Index

Natural Gas and Oil Reserves

The Partnership’s gas and oil reserves are located in the United States. The Partnership’s reserve estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and subsequent SEC staff regulations, interpretations and guidance. The Managing General Partner has 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 an internal team composed of 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 any 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 released in January 2009, Modernization of Oil and Gas Reporting.

Proved reserves are those quantities of oil and natural gas, 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 conditions, operating methods, and government regulations. These reserve quantities should be producible prior to the operating contract term’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.

- 5 -

Index

The table below presents information as of December 31, 2009, regarding the Partnership’s proved reserves by production field, as estimated by Ryder Scott. 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 represent the reserves attributable to the future recompletions of the Codell formation in the Wattenberg Field wells. For additional information regarding the Partnership’s natural gas and oil reserves see Supplemental Oil and Gas Information – Unaudited, Net Proved Natural Gas and Oil Reserves accompanying the financial statements included in this report.

	As of December 31, 2009
					Natural Gas
	Oil		Natural Gas		Equivalent
	(MBbl)		(MMcf)		(MMcfe)		Percent
Proved developed
Piceance Basin: Grand Valley Field		25		11,378		11,528		71	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		351		1,756		3,862		24	%
Williston Basin: Bailey and Carter Fields		134		48		852		5	%
Total proved developed		510		13,182		16,242		100	%

Proved undeveloped
Piceance Basin: Grand Valley Field		-		-		-		0	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		578		2,894		6,362		100	%
Williston Basin: Bailey and Carter Fields		-		-		-		0	%
Total proved undeveloped		578		2,894		6,362		100	%

Proved reserves
Piceance Basin: Grand Valley Field		25		11,378		11,528		51	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		929		4,650		10,224		45	%
Williston Basin: Bailey and Carter Fields		134		48		852		4	%
Total proved reserves		1,088		16,076		22,604		100	%

In 2009, the SEC published its final rule regarding the modernization of oil and gas reporting, which changed the valuation price of in-ground natural gas and oil resources, used to determine economically producible natural gas and oil reserve quantities, from a year-end single-day pricing method 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.

- 6 -

Index

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, through the D&O Agreement, is the operator 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 which are 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 winter weather conditions and time periods reserved by leasehold restrictions designed to protect wildlife habitat can exist and limit operational capabilities for as long as six months. These factors may adversely affect some Partnership production operations. In addition to cold weather, operational constraint challenges such as surface equipment freezing can limit production volumes. Increased competition and higher costs during milder weather and habitat protection periods for oil field equipment, services, supplies and qualified personnel can adversely affect profitability and cash distributions to the Investor Partners.

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

	Producing Wells
	Gas				Oil				Total
Location	Gross		Net		Gross		Net		Gross		Net
State of Colorado
Piceance Basin: Grand Valley Field		23.0		22.3		-		-		23.0		22.3
Denver-Julesburg (DJ) Basin: Wattenberg Field		63.0		62.9		-		-		63.0		62.9
Total Colorado		86.0		85.2		-		-		86.0		85.2

State of North Dakota
Williston Basin: Bailey and Carter Fields		3.0		2.9		2.0		1.6		5.0		4.5
Total North Dakota		3.0		2.9		2.0		1.6		5.0		4.5

Total Productive Wells		89.0		88.1		2.0		1.6		91.0		89.7

The Partnership’s operating areas are profiled as follows:

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

Piceance Basin, Grand Valley Field in Garfield County, Colorado. Located near the western border of Colorado, the Partnership’s wells in this field have also exhibited production histories typical for wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively shallow decline. These wells generally produce natural gas along with small quantities of oil. The majority of development wells drilled in the area are 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.

- 7 -

Index

Williston Basin, Bailey Field in Dunn County and Carter Field in Burke County, North Dakota. Located in the western portion of North Dakota, the Partnership’s wells in the Bailey Field are development wells drilled approximately 15,000 feet to the Bakken Shale interval which produces oil in addition to natural gas. The Partnership’s Carter Field development and exploratory wells produce oil and were completed to the Nesson formation utilizing multi-lateral well bores where true vertical depths vary from 5,000 to 8,000 feet with total measured well depths, including the lateral well bore(s) ranging from approximately 10,000 to 20,000 feet.

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. 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, Bailey Field, and to a lesser extent Grand Valley Field, wells also produce oil in addition to natural gas. The Partnership’s Carter Field wells are oil wells. 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.

- 8 -

Index

Oil and Gas 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		1,495,118		2,104,766
Denver-Julesberg (DJ) Basin: Wattenberg Field		341,324		404,682
Williston Basin: Bailey and Carter Fields		12,893		22,405
Total Natural Gas		1,849,335		2,531,853

Oil (Bbls)
Piceance Basin: Grand Valley Field		4,673		5,887
Denver-Julesberg (DJ) Basin: Wattenberg Field		75,651		105,871
Williston Basin: Bailey and Carter Fields		25,415		37,683
Total Oil		105,739		149,441

Natural gas equivalent (Mcfe)
Piceance Basin: Grand Valley Field		1,523,156		2,140,088
Denver-Julesberg (DJ) Basin: Wattenberg Field		795,230		1,039,908
Williston Basin: Bailey and Carter Fields		165,383		248,503
Total natural gas equivalent		2,483,769		3,428,499

Natural Gas and Oil Sales

Natural gas sales
Piceance Basin: Grand Valley Field	$	3,844,959	$	13,457,661
Denver-Julesberg (DJ) Basin: Wattenberg Field		1,406,606		3,219,140
Williston Basin: Bailey and Carter Fields		84,990		257,643
Total natural gas sales		5,336,555		16,934,444

Oil sales
Piceance Basin: Grand Valley Field	$	208,516	$	476,868
Denver-Julesberg (DJ) Basin: Wattenberg Field		4,094,816		9,408,131
Williston Basin: Bailey and Carter Fields		1,288,320		3,139,804
Total oil sales		5,591,652		13,024,803

Natural gas and oil sales
Piceance Basin: Grand Valley Field	$	4,053,475	$	13,934,529
Denver-Julesberg (DJ) Basin: Wattenberg Field		5,501,422		12,627,271
Williston Basin: Bailey and Carter Fields		1,373,310		3,397,447
Total natural gas and oil sales	$	10,928,207	$	29,959,247

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

Natural gas (per Mcf)
Piceance Basin: Grand Valley Field	$	2.57	$	6.39
Denver-Julesberg (DJ) Basin: Wattenberg Field		4.12		7.95
Williston Basin: Bailey and Carter Fields		6.59		11.50
Average sales price natural gas, all fields		2.89		6.69

Oil (per Bbl)
Piceance Basin: Grand Valley Field	$	44.62	$	81.00
Denver-Julesberg (DJ) Basin: Wattenberg Field		54.13		88.86
Williston Basin: Bailey and Carter Fields		50.69		83.32
Average sales price oil, all fields		52.88		87.16

Natural gas equivalent (per Mcfe)
Piceance Basin: Grand Valley Field	$	2.66	$	6.51
Denver-Julesberg (DJ) Basin: Wattenberg Field		6.92		12.14
Williston Basin: Bailey and Carter Fields		8.30		13.67
Average sales price natural gas equivalents, all fields		4.40		8.74

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

Piceance Basin: Grand Valley Field	$	1.15	$	1.02
Denver-Julesberg (DJ) Basin: Wattenberg Field		1.18		0.86
Williston Basin: Bailey and Carter Fields		2.18		1.72
Average production cost, all fields		1.22		1.03

- 9 -

Index

(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.

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 oil and natural gas sales to achieve a more predictable cash flow and to reduce exposure to fluctuations in oil and natural gas 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.

- 10 -

Index

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.

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.

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

North Dakota oil sales dedication is multi-year and extends throughout the well’s economic life.

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.

- 11 -

Index

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 recent economic downturn which has weakened U.S. oil and natural gas demand and disrupted global credit markets, which third-party entities access for pipeline expansion financing.

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 oil and natural gas. The Partnership competes with entities having financial and human resources substantially larger than those available to the Partnership. Because there are thousands of oil and natural gas 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. 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 from time to time, with the intent of reducing the current global oversupply caused by the global economic downturn while maintaining or increasing price levels. 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, oil and natural gas produced and sold from the Partnership's wells.

- 12 -

Index

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 oil and natural gas 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 oil and natural gas produced from the Partnership’s wells, the Partnership designated PDC as its oil and natural gas 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 oil and natural gas. 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.

- 13 -

Index

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 and North Dakota 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. PDC sells the Partnership’s North Dakota natural gas to Bear Paw Energy, LLC (“Bear Paw”) which owns natural gas gathering and processing operations in the Williston Basin, North Dakota area.

The Partnership’s Colorado 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 Colorado wells to Teppco Crude Oil, LP (“Teppco”). Beginning January 1, 2009, Suncor became the Partnership’s primary Colorado oil purchaser. The Partnership’s primary purchaser of North Dakota oil is Shell Trading (US) Company (“STUSCO”).

Industry Regulation

While the prices of oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas, to prevent waste of oil and natural gas, 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.

- 14 -

Index

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. Current federal and state proposed regulations expected to impact the industry, if enacted, include the following:

Congressional legislation which could 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 could affect the Partnership and the third parties that process the Partnership’s natural gas and oil.

Federal regulatory proposals, which could limit the use of over-the-counter (OTC) derivatives, including the oil and gas price hedging the Managing General Partner currently uses. Limits on the use of OTC instruments could impair the Managing General Partner’s use of these derivatives and could limit the Partnership’s ability to protect its cash flows and reduce commodity price risk.

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.

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. See Note 9, Commitments and Contingencies−Other to the Partnership’s accompanying financial statements to this report.

Partnership expenses relating to preserving the environment have risen over the past two years and are expected to continue. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. While environmental regulations have had no materially adverse effect on its 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 operations.

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.

- 15 -

Index

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 0001376912. 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 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.

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.

[Reserved]

- 16 -

Index

PART II

Item 5.

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

At December 31, 2009, the Partnership had 2,019 Investor Partners holding 4,497.03 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 Managing General Partner. As of December 31, 2009, the Managing General Partner has repurchased 8.0 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 be able to sell them only for less than fair market value. The offer and sale of the Investor Partners' interests ("units") have not been registered under the Securities Act or under any state securities laws. Each purchaser of units was required to represent that such individual investor partner was purchasing the units for his or her own account for investment and not with a view to distribution. No transfer of a unit may be made unless the transferee is an "accredited investor" and such transfer is registered under the Securities Act and applicable state securities laws, or an exemption there from is available. 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 will have to hold his or her partnership interests indefinitely and will 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 63% of available cash to the Investor Partners, including any Investor Partner units purchased by the Managing General Partner, and 37% of available 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 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 distribution upon the Partnership having sufficient cash available for distribution. Sufficient cash available for distribution is defined to generally mean 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 debt instruments or 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.

- 17 -

Index

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	$	15,667,089
For the year ended December 31, 2008		26,226,112

For the period from the Partnership's inception to December 31, 2009	$	62,538,729

The volume of production from producing properties naturally declines with the passage of time and is 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 oil and natural gas production, or significant increases in the production of oil and natural gas from the successful additional development of these properties, if any. When the Partnership decides to develop its wells further, the initial funds necessary for that development would come from any combination of retention of the Partnership's distributable cash flows or borrowed funds. As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners may decrease. 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.

The Agreement permits the Partnership to borrow funds on behalf of the Partnership for Partnership activities, exclusive of funds for the payment of cash distributions. The Partnership may borrow needed funds from the Managing General Partner or from unaffiliated persons. On loans or advances made available to the Partnership by the Managing General Partner, the Managing General Partner may not receive interest in excess of its interest costs, nor may the Managing General Partner receive interest in excess of the amounts which would be charged the Partnership (without reference to the Managing General Partner's financial abilities or guarantees) by unrelated banks on comparable loans for the same purpose. The Managing General Partner anticipates that borrowed funds may be utilized to finance Codell recompletion activities (see Item 1, Business−Business Strategy, Development). As the Partnership may have to pay interest on borrowed funds, the amount of Partnership funds available for distribution to the partners of the Partnership may be reduced accordingly.

Unit Repurchase Program. Beginning in May 2010, the third anniversary of the date of the first Partnership distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units. 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.

- 18 -

Index

In addition to the above repurchase program, individual investor partners periodically offer and PDC repurchases, 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 negotiated-basis limited partner unit repurchases during the three months ended December 31, 2009.

Period	Total Number of Units Repurchased		Average Price Paid per Unit

October 1−31, 2009		-	$	-
November 1−30, 2009		2.50		6,000
December 1−31, 2009		-		-
Total fourth quarter Unit Repurchase Program repurchases		2.50

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.

Partnership Overview

Rockies Region 2006 Limited Partnership engages in the development, production and sale of oil and natural gas. The Partnership began oil and gas operations in September 2006 and currently operates 91 gross (89.7 net) wells located in the state of Colorado and North Dakota. 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 could be affected by demand factors.

The Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, Partnership well recompletions in the Codell formation of Wattenberg Field wells may provide for additional reserve development and production. These well recompletions generally occur five to ten years after initial well drilling so that well resources are optimally utilized and would be expected to occur within a favorable general economic environment and commodity price structure. The Managing General Partner has developed a plan to initiate recompletion activities during 2012. This plan includes notifying investor partners that funding for these recompletions will be procured through any combination of bank borrowings or withholding of future distributable cash flows of the Partnership resulting from both current production and any increased production due to recompletion activities. The funds retained 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 made available to the Partnership, through these funding sources. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed. Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion. As the optimal period approaches, the Managing General Partner will re-evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion. Additionally, further-developed Partnership wells may not generate sufficient funds from production to repay financial obligations of the Partnership for borrowed funds, plus interest. All borrowings will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for loan repayment.

- 19 -

Index

2009 Overview

Even with natural gas prices rebounding somewhat in the last two months of 2009 from earlier in the year, the Partnership continued to experience a depressed natural gas commodity pricing market throughout 2009 compared to 2008. The Partnership’s production decreased to 2,484 MMcfe for the 2009 annual period compared to 3,428 MMcfe for the same 2008 period, a decrease of 28%. The Partnership’s average sales price for 2009 declined to $4.40 per Mcfe, a decrease of 50% from the annual sales price a year ago. While the significant changes in commodity prices have impacted the Partnership’s results of operations, 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 successful. Although the Partnership’s 2009 natural gas and oil sales revenues declined by $19.0 million compared to 2008, the Partnership’s annual cash flows provided by operating activities decreased by $9.8 million, or 39%, primarily benefited by the Partnership’s increase in realized derivative gains for the 2009 annual period to $6.6 million and the reduction in “Due from Managing General Partner –Other, Net” of $2.0 million. These realized derivative gains added $2.68 per Mcfe to the Partnership’s average sales price noted above.

- 20 -

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)		91		91			*

Production: (1)
Natural gas (Mcf)		1,849,335		2,531,853			-27	%
Oil (Bbl)		105,739		149,441			-29	%
Natural gas equivalents (Mcfe) (2)		2,483,769		3,428,499			-28	%
Mcfe per day		6,805		9,393			-28	%

Natural Gas and Oil Sales
Natural gas	$	5,336,555	$	16,934,444			-68	%
Oil		5,591,652		13,024,803			-57	%
Total natural gas and oil sales	$	10,928,207	$	29,959,247			-64	%

Realized Gain (Loss) on Derivatives, net
Natural gas derivatives - realized gain	$	5,069,757	$	1,013,121			*
Oil derivatives - realized gain (loss)		1,575,087		(432,928	)		*
Total realized gain on derivatives, net	$	6,644,844	$	580,193			1045	%

Average Selling Price (excluding realized gain (loss)on derivatives)
Natural gas (per Mcf)	$	2.89	$	6.69			-57	%
Oil (per Bbl)		52.88		87.16			-39	%
Natural gas equivalents (per Mcfe)		4.40		8.74			-50	%

Average Selling Price (including realized gain (loss)on derivatives)
Natural gas (per Mcf)	$	5.63	$	7.09			-21	%
Oil (per Bbl)		67.78		84.26			-20	%
Natural gas equivalents (per Mcfe)		7.08		8.91			-21	%

Average cost per Mcfe
Natural gas and oil production cost (3)	$	1.41	$	1.50			-6	%
Depreciation, depletion and amortization		3.75		3.35			12	%

Operating costs and expenses:
Direct costs - general and administrative	$	562,310	$	673,877			-17	%
Depreciation, depletion and amortization	$	9,302,635	$	11,496,628			-19	%

Cash distributions	$	15,667,089	$	26,226,112			-40	%

* 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)

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

- 21 -

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 64% decrease in total sales in 2009 as compared to 2008 was due to the combined effects of decreased production volumes, on a Mcfe or energy equivalency basis, of 28% and a significantly lower average sales price per Mcfe, of 50%.

Commodity price declines contributed $10.8 million while volume reductions added $8.2 million to the $19.0 million decrease in oil and natural gas sales in 2009 compared to the prior year. The decrease in natural gas and oil sales revenue was partially offset by realized derivative gains during 2009 of $6.6 million. See Commodity Price Risk Management, Net discussion below.

The decrease in natural gas revenues of 68% contrasts to the more moderate reduction in oil revenues of 57% which reflects the less significant reduction in average oil sales prices (39%) as compared to the reduction in natural gas sales prices (57%) during the period. The Partnership expects to experience continued declines in both oil and natural gas production volumes over the wells’ life cycles until the Wattenberg Field wells are recompleted.

Natural Gas and Oil Pricing

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

The price the Partnership receives for the natural gas produced in the Rocky Mountain Region is based on a variety of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices. The CIG Index, and other indices for production delivered to Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily NYMEX based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets. This negative differential has narrowed in recent months and for two out of the last four months become a slight positive differential, which contradicts 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 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. 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.

- 22 -

Index

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, uses various derivative instruments to manage fluctuations in oil and natural gas 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, if the applicable index rises above the ceiling price, the Managing General Partner pays the counterparty; however, if the index drops below the floor price, the counterparty pays the Managing General Partner. Under the Partnership’s commodity swap arrangements, if the applicable index rises above the swap price, the Managing General Partner pays the counterparty; however, if the index drops below the swap price, the counterparty pays the Managing General Partner. Under the Partnership’s basis protection swaps, if the differential widens, then the counterparty pays the Managing General Partner; however, if the differential narrows, then the Managing General Partner pays the counterparty. 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.

The following table presents the Partnership’s commodity price risk management (loss) gain, net.

	Year Ended December 31,
Commodity price risk management, net	2009			2008
Realized gains (losses)
Oil	$	1,575,087		$	(432,928	)
Natural Gas		5,069,757			1,013,121
Total realized gain, net		6,644,844			580,193

Unrealized gains (losses)
Reclassification of realized (gains) losses included in prior periods unrealized		(5,772,392	)		1,080,170
Unrealized (loss) gain for the period		(3,611,794	)		7,481,618
Total unrealized (loss) gain, net		(9,384,186	)		8,561,788
Commodity price risk management (loss) gain, net	$	(2,739,342	)	$	9,141,981

Realized gains recognized in 2009 of $6.6 million are a result of lower natural gas and oil commodity prices at settlement compared to the respective strike price. During 2009, the Partnership recorded unrealized derivative losses of $3.7 million on the Partnership’s CIG basis swaps, as the forward basis differential between NYMEX and CIG continued to narrow and became a positive differential for two of the last four month’s settlements, and unrealized derivative losses of $1.0 million on the Partnership’s oil positions, both of which were offset by unrealized derivative gains of $1.1 million on the Partnership’s natural gas positions.

In periods of rising prices, the Partnership will generally record losses on its derivative positions as fair values exceed contract prices determining the Partnership’s oil and natural gas sales. Conversely, in periods of decreasing prices, the Partnership will generally recognize gains on its derivative positions.

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.

- 23 -

Index

The following table presents the Partnership’s derivative positions in effect as of December 31, 2009.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-Mmbtu)		Weighted Average Contract Price				Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at December 31, 2009(1)
Commodity/ Index	Quantity (Gas-Mmbtu)		Floors		Ceilings		Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at December 31, 2009(1)

Natural Gas
CIG
1Q 2010		185,028	$	7.50	$	7.50		129,861	$	9.20		-	$	-		$	901,672
4Q 2010		79,402		4.75		9.45		-		-		-		-			14,261
2011		119,103		4.75		9.45		-		-		-		-			6,813

NYMEX
2Q 2010		-		-		-		295,650		5.55		288,100		(1.88	)		(414,549	)
3Q 2010		-		-		-		285,335		5.55		278,537		(1.88	)		(469,125	)
4Q 2010		30,275		5.75		8.30		160,106		6.08		188,334		(1.88	)		(258,268	)
2011		40,636		5.75		8.30		801,535		6.77		842,171		(1.88	)		(681,454	)
2012		55,443		6.00		8.27		795,163		6.98		850,608		(1.88	)		(631,417	)
2013		-		-		-		763,069		7.12		763,069		(1.88	)		(536,696	)
Total Natural Gas		509,887						3,230,719				3,210,819					(2,068,763	)

Oil
NYMEX
1Q 2010		-		-		-		10,696		92.96		-		-			136,709
2Q 2010		-		-		-		10,816		92.96		-		-			121,024
3Q 2010		-		-		-		10,934		92.96		-		-			107,941
4Q 2010		-		-		-		10,934		92.96		-		-			94,900
2011		-		-		-		19,554		70.75		-		-			(294,379	)
Total Oil								62,934									166,195

Total Natural Gas and Oil																$	(1,902,568	)

(1) Approximately 56% of the total fair value of the derivative assets and 98% of liabilities were measured using significant unobservable inputs. See Note 4, Fair Value Measurements, to the accompanying financial statements included in this report.

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. As production is expected to continue to decline, production costs per unit can be expected to increase.

Generally, natural gas and oil production costs vary with changes in total oil and natural gas sales and production volumes. Property and severance taxes are estimates by the Managing General Partner based on rates determined using historical information. These amounts are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Property and severance taxes vary directly with total oil and natural gas sales. Transportation costs vary directly with production volumes. Fixed monthly well operating costs increase on a per unit basis as production decreases per the historical decline curve. 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 were lower by $1.6 million, or 32%, due to volume-associated reductions of $1.1 million in production taxes, natural gas transportation and lease operating expenses. In addition to volume-associated production tax decreases, lower commodity valuations further lowered production taxes by approximately $0.7 million. However, lease operating costs increased by $0.2 million due to a fourth quarter Grand Valley Field well workover. Natural gas and oil production costs per Mcfe were $1.41 during the year 2009 compared to $1.50 for the year 2008.

- 24 -

Index

Direct Costs – General and Administrative

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs declined during 2009 compared to the same period in 2008, by approximately $0.1 million, due to a reduction of Colorado Royalty Settlement costs. For more information on the Colorado Royalty Settlement, see Note 6, Commitments and Contingencies.

Depreciation, Depletion and Amortization

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 reserves and is determined by these reserves and their 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 oil and gas 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. If valuation prices increase, the estimated volumes of natural gas and oil reserves will increase, resulting in decreases in the rate of DD&A for each Mcfe produced. If valuation prices decrease, the estimated volumes of natural gas and oil reserves will decrease resulting in increases in the rate of DD&A for each Mcfe produced.

The DD&A expense rate per Mcfe increased to $3.75 for the year ended December 31, 2009, compared to $3.35 during the same period in 2008. The variance in the per Mcfe rates for 2009 compared to 2008 is partially the result of the changing production mix between the Partnership’s Wattenberg, Grand Valley and Bailey Fields, which have significantly different DD&A rates, and the overall production volume decline of 28% which reduced DD&A expense by $3.2 million in 2009 compared to the previous year. Production-related DD&A expense reductions were offset however, by a $1.1 million increase in DD&A expense during the first three quarters of 2009 as a consequence of lower proved developed producing natural gas and oil reserves reported in the Partnership’s annual December 31, 2008 reserve report which resulted in higher DD&A rates in effect through September 30, 2009, than during the comparable periods of 2008. During fourth quarter 2009, increases in the Partnership’s Wattenberg Field proved developed producing natural gas and oil reserves reported in the December 31, 2009 annual reserve report, contributed to a DD&A expense reduction of $0.1 million from the fourth quarter 2008 DD&A expense. Overall, DD&A expense during 2009 decreased $2.2 million from that of the previous year. See Supplemental Oil and Gas Information – Unaudited, Net Proved Natural Gas and Oil Reserves for additional information regarding the Partnership’s reserves reported as of December 31, 2009 and 2008.

Loss on Impairment of Oil and Gas Properties

Exploratory Dry Hole Costs

The Partnership incurred exploratory dry hole costs of approximately $0.1 million for the years ended December 31, 2009 and 2008, respectively, which represent final plugging, abandonment and environmental reclamation costs for the Partnership’s Colorado and North Dakota exploratory dry holes.

- 25 -

Index

Liquidity and Capital Resources

The Partnership’s primary sources of cash in 2009 were from funds generated from 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 commodity prices, change in production volumes and realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership manages 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, realized derivative gains or losses and the decrease in “Due from Managing General Partner – Other, Net.” However, the Partnership does not hold derivative instruments for 100% of the Partnership’s expected future production and therefore may still experience significant fluctuations in our cash flows from operations. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.

The Partnership’s future operations are expected to be conducted with available funds and revenues generated from oil and natural gas production activities and commodity gains (losses). Oil and gas production from the Partnership’s existing properties are expected to continue a gradual decline over the remaining life of the wells. Therefore, the Partnership expects a lower annual level of oil and gas production and, in the absence of significant price increases, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Investor Partners in 2012 and beyond. Future cash distributions may also be reduced to fund well recompletions in the Codell formation of the Wattenberg Field.

In 2008 the Partnership incurred additional drilling costs of $1,068,657 in excess of drilling advances paid to the Managing General Partner. This amount has been recorded as a liability in the account "Due from (to) Managing General Partner - other" and will be funded by a reduction in future distributable cash flows. No Partnership distributable cash flows for the year 2009 were retained for the payment of this obligation.

Working Capital

Working capital at December 31, 2009 was $1.5 million compared to working capital of $9.3 million at December 31, 2008. This decrease of $7.8 million was primarily due to the following changes in accounts receivable balances:

Natural gas and oil receivables decreased to $2.1 million as of December 31, 2009, from $3.5 million as of December 31, 2008.

Realized derivative gains receivables decreased to $1.0 million as of December 31, 2009, from $2.3 million as of December 31, 2008

Net short-term unrealized derivative gains receivable decreased to $0.2 million as of December 31, 2009, from $5.8 million as of December 31, 2008

Additionally, during the third quarter 2009 there was a reduction of $0.2 million in amounts due from the Managing General Partner due to the Partnership’s settlement of the obligation for the Colorado Royalty Settlement of approximately $0.2 million. The net cash impact of this transaction decreased distributions by $0.2 million during 2009. For more information on the Colorado Royalty Settlement see Note 9, Commitments and Contingencies to the accompanying audited financial statements.

Cash Flows

Cash Flows From Investing Activities

The Partnership utilized approximately $0.1 million during 2009 for the installation of a Wattenberg Field compressor unit that improved production deliverability and $1.3 million in capital during 2008 for the development of oil and gas properties. During 2009, the Partnership realized proceeds of approximately $0.1 million in the sale of surplus Carter Field equipment and State of Colorado sales tax refunds related to tangible well equipment purchases during previous-year drilling operations. During 2008, the Partnership realized approximately $0.1 million in proceeds from the sale to non-affiliated third-parties, two Wattenberg Field commercially unproductive exploratory wells evaluated to be dry holes.

- 26 -

Index

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in May 2007 and has distributed $62.5 million through December 31, 2009. The table below presents the cash distributions to the Managing General Partner and Investor Partners including Managing General Partner distributions relating to limited partnership units repurchased for the periods described as follows:

Year Ended	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions

2009	$	5,796,820	$	9,870,269	$	15,667,089

2008	$	9,736,727	$	16,489,385	$	26,226,112

Investor Partner cash distributions include $11,412 and $11,261 during the years 2009 and 2008, respectively, related to equity cash distributions on Investor Partner units repurchased by the Managing General Partner. There were no limited partnership units repurchased by PDC, the Managing General Partner, prior to 2009.

Cash Flows From Operating Activities

Net cash provided by operating activities was $15.5 million for 2009 compared to $25.3 million for 2008, a decrease of $9.8 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 $22.5 million, or 65%;

An increase in realized commodity price risk management, net of $6.1 million, a decrease in natural gas and oil production costs of $1.6 million, or 32%, and a decrease in direct costs – general and administrative of approximately $0.1 million; and

A reduction in “Due from Managing General Partner – Other, Net,” of $0.2 million in third quarter 2009, due to Partnership’s approximately $0.2 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.

No bank borrowings or significant advances by the Managing General Partner are anticipated until such time as recompletions of the Codell formation in the Wattenberg Field wells are undertaken by the Partnership, which is expected to occur in 2012 or later. These borrowings, if any, will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for repaying the loan.

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. This 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:

- 27 -

Index

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.

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, collects a price, 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 New York Mercantile Exchange, or 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 Colorado Interstate Gas, or CIG, based fixed-price natural gas swaps, oil swaps, natural gas and oil collars, and the Partnership’s natural gas basis protection derivative instruments.

- 28 -

Index

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. As of December 31, 2009, 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.

Natural Gas and Oil Properties

The Partnership accounts for its oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells 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.

Cumulative in-progress exploratory well drilling costs are initially capitalized as “Suspended well costs” until the well’s productive status becomes known. If the well is determined to be economically nonproductive, the well’s capitalized costs are expensed, as are any subsequent costs to plug, abandon and environmentally remediate the well site. The Partnership’s three D Sand and J Sand formations Wattenberg Field exploratory wells, one Nesson formation Coteau Field exploratory well and one Nesson formation Wildcat Field exploratory well were determined to be economically unproductive and declared dry holes, during 2007 and were plugged and abandoned, or sold, during 2007 and 2008; accordingly, the initial cumulative costs to drill the well were charged to the line caption, “Exploratory dry hole costs” on the Partnership’s statements of operations during previous years. Since inception through December 31, 2009, the Partnership recorded $8.3 million in exploratory dry hole costs. The Partnership will conduct no future exploratory drilling activities.

The Partnership accounts for the impairment or disposal of long-lived assets, by periodically assessing its proved natural gas and oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated future production based upon estimated prices at which the Partnership reasonably estimates the commodity could be sold. The estimates of future prices may differ from current market prices of oil and natural gas. Downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs may result in a triggering event and therefore a possible impairment of the Partnership’s oil and natural gas properties. If, when assessing impairment, net capitalized costs exceed undiscounted future net cash flows, impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed fair value. Although cash flow estimates used by the Partnership are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. The Partnership incurred impairment losses during 2008 of $3.8 million on its Bailey and Carter Fields proved oil and natural gas properties. There were no additional impairments recognized during 2009; thus, the Partnership’s has recorded total impairments of $13.4 million since the Partnership’s inception, for these two fields.

- 29 -

Index

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies−to the Partnership’s accompanying financial statements included in this report.

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.

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Previous Independent Registered Public Accounting Firm

As previously reported on Form 8-K filed with the SEC on June 2, 2009, Petroleum Development Corporation, the managing general partner of Rockies Region 2006 Limited Partnership, recommended, and the Audit Committee of the Board of Directors of PDC ratified, the dismissal of Schneider Downs & Co., Inc. (“Schneider Downs”) as the Partnership’s Independent Registered Public Accounting Firm on May 28, 2009. The Partnership does not have its own audit committee and, therefore, relies upon and utilizes the services of the managing general partner’s audit committee.

The audit report of Schneider Downs on the Partnership’s financial statements as of December 31, 2008 and 2007, did not contain an adverse opinion or a disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope, or accounting principles.

In connection with the audit of the fiscal year ended December 31, 2008 and 2007, and the subsequent interim period through May 28, 2009, there were no: (1) disagreements with Schneider Downs on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreement(s), if not resolved to their satisfaction, would have caused them to make reference in connection with their report to the subject matter of the disagreement(s), or (2) reportable events, except that:

(1)

The following material weakness in internal control over financial reporting was identified related to the fiscal year ended December 31, 2008, and the subsequent interim period through May 28, 2009, as follows:

- 30 -

Index

The Partnership did not maintain effective internal controls over financial reporting as of December 31, 2008, over transactions that are directly related to and processed by the Partnership, in that the Partnership failed to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over financial reporting. More specifically, the Partnership’s financial close and reporting narrative failed to adequately describe the process, identify key controls and assess segregation of duties. This material weakness has not yet been remediated as of May 28, 2009.

Schneider Downs has been authorized to respond fully to the inquiries of the successor independent registered public accounting firm concerning the subject matter of the foregoing.

The Partnership has provided Schneider Downs with a copy of the foregoing statements and requested that Schneider Downs furnish the Partnership with a letter addressed to the SEC stating whether Schneider Downs agrees with the foregoing statements, and, if not, stating the respects in which Schneider Downs does not agree. The letter from Schneider Downs was attached as Exhibit 16 to the Partnership’s Form 8-K filed with the SEC on June 2, 2009.

New Independent Registered Public Accounting Firm

As previously reported on the Partnership’s Form 8-K filed with the SEC on June 2, 2009, the Audit Committee of the managing general partner recommended and its Board of Directors ratified the engagement of PricewaterhouseCoopers LLP ("PwC") as the Registrant's independent registered public accounting firm.

During the two fiscal years ended December 31, 2008, and through May 28, 2009, the Partnership has not consulted with PwC regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed; or the type of audit opinion that might be rendered on the Partnership’s financial statements, and neither a written report was provided to the Partnership nor oral advice was provided that PwC concluded was an important factor considered by the Partnership in reaching a decision as to the accounting, auditing or financial reporting issue; or (ii) any matter that was either the subject of a disagreement, as that term is defined in Item 304(a)(1)(iv) of SEC Regulation S-K, or a reportable event required to be reported under Item 304(a)(1)(v) of Regulation S-K.

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.

2008 Material Weakness

As discussed in the Management’s Report on Internal Control Over Financial Reporting included in the Partnership’s 2008 Annual Report on Form 10-K, the Partnership did not maintain effective internal controls over financial reporting as of December 31, 2008, over transactions that are directly related to and processed by the Partnership, in that the Partnership failed to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over financial reporting. More specifically, the Partnership’s financial close and reporting narrative failed to adequately describe the process, identify key controls and assess segregation of duties. This material weakness has 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.

- 31 -

Index

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.

This 2009 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. Pursuant to Final Order dated October 19, 2009, temporary Item 308T was extended through December 15, 2010. Accordingly, the Partnership will file the attestation report of the Partnership’s independent registered public accounting firm regarding internal control with the Partnership’s Annual Report on Form 10-K as of December 31, 2010.

(b) Remediation of Material Weakness in Internal Control

PDC, the Managing General Partner, with participation from the Audit Committee of its Board of Directors, addressed the material weakness disclosed in the Partnership’s 2008 Annual Report on Form 10-K. The Managing General Partner believes that the effective implementation of changes in internal controls over financial reporting outlined below remediated this known material weakness as of December 31, 2009.

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 2009.

In the second quarter, the Partnership developed and implemented 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 has 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.

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.

- 32 -

Index

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

Item 9B.

Other Information

None

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. 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 Board has established the Planning and Finance Committee to oversee the responsibilities of the Board related to planning and finance with respect to the risk assessment and management process that includes 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. The 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 the integrity of the financial reporting systems and internal controls as well as PDC’s legal and regulatory compliance. In addition to these two standing committees, 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.

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:

- 33 -

Index

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

Market-responsive oil and gas marketing and prudent field operations cost management which support predictable 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 Relations.

Although the Partnership has no Code of Ethics, PDC has a Code of Ethics that applies to its senior executive officers. The Code of Ethics is posted on PDC’s website at www.petd.com.

Since 1969, PDC has been engaged in the business of exploring for, developing and producing oil and gas primarily in the Appalachian and Michigan Basins and Rocky Mountain Region. Approximately 36% of the 5,000 oil and natural gas wells owned by PDC are located in the DJ and Piceance Basins where the Partnership operates. PDC’s significant operational capacity in these two areas, particularly in the DJ Basin where PDC is one of the top 5 operators among 170 who control 90% of the basin’s acreage, enables it to be an effective and low cost operator in both basins. PDC began sponsoring drilling partnerships in 1984 and sponsored one or more every year through 2007. PDC did not offer new drilling partnerships in 2008 or 2009, and has no plans to make any offers throughout 2010 or beyond. In October 2009, PDC announced the creation of a new joint venture with an unrelated third-party to develop PDC’s Marcellus Shale acreage and shallow Devonian assets in the Appalachian Basin. Because PDC must divide its managerial and technical staff’s attention directing the operation of PDC’s own corporate interests, the affairs of the 32 other limited partnerships for which PDC services as operator and Managing General Partner and business start-up of the new Appalachian Basin joint venture, the Partnership will not receive PDC's full attention and efforts at all times. However, the Board believes that the organization continues to dedicate sufficient time, attention and expertise to the Partnership to appropriately manage the affairs of the Partnership.

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's internet address is www.petd.com. PDC posts on its internet web site its periodic and current reports and other information, including its audited financial statements which it files with the SEC, as well as various charters and other corporate governance information.

- 34 -

Index

Petroleum Development Corporation

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

Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires

Richard W. McCullough	58	Chairman and Chief Executive Officer	2007	2010

Gysle R. Shellum	58	Chief Financial Officer	-	-

R. Scott Meyers	35	Chief Accounting Officer	-	-

Daniel W. Amidon	49	General Counsel and Secretary	-	-

Barton R. Brookman, Jr.	47	Senior Vice President Exploration and Production	-	-

Lance Lauck	47	Senior Vice President Business Development	-	-

Vincent F. D'Annunzio	57	Director	1989	2010

Jeffrey C. Swoveland	55	Director	1991	2011

Kimberly Luff Wakim	51	Director	2003	2012

David C. Parke	43	Director	2003	2011

Anthony J. Crisafio	57	Director	2006	2012

Joseph E. Casabona	66	Director	2007	2011

Larry F. Mazza	49	Director	2007	2010

James M. Trimble	61	Director	2009	2010

Richard W. McCullough was appointed Chief Executive Officer in June 2008 and Chairman in November 2008. Mr. McCullough also served PDC as President since March 2008. Mr. McCullough served as Chief Financial Officer from November 2006 until November 2008. Prior to joining PDC, Mr. McCullough served as an energy consultant from July 2005 to November 2006. From January 2004 to July 2005, Mr. McCullough served as President and Chief Executive Officer of Gasource, LLC, Dallas, Texas, a marketer of long-term, natural gas supplies. From 2001 to 2003, Mr. McCullough served as an investment banker with J.P. Morgan Securities, Atlanta, Georgia, and served 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. Mr. McCullough, a CPA, was a practicing certified public accountant for 8 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 effective November 11, 2008. Prior to joining PDC, 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. Prior thereto from March 2001 until September 2004, Mr. Shellum served as a consultant to Value Capital, a private consulting firm in Dallas, 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.

- 35 -

Index

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.

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.

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.

Lance Lauck was appointed Senior Vice President Business Development on August 31, 2009. Prior to joining PDC, Mr. Lauck served as Vice President Acquisitions and Business Development with Quantum Resources Management, LLC based in Denver Colorado. Beginning in June 2006, Mr. Lauck was responsible for valuation and acquisition of oil and gas exploration and production properties. Prior to his employment at Quantum Resources, Mr. Lauck was employed by Anadarko Petroleum Corporation from 1988 to 2006 in The Woodlands, Texas. Mr. Lauck served Anadarko in various capacities beginning as a Senior Production Engineer and exited as General Manager, Corporate Development.

Vincent F. D’Annunzio has served as president of Beverage Distributors, Inc. located in Clarksburg, West Virginia since 1985. Mr. D’Annunzio serves as Chairman of the Nominating and Governance Committee and serves on the Executive Committee and the Compensation Committee.

Jeffrey C. Swoveland has served as Chief Operating Officer of ReGear, Inc. (previously named Coventina Healthcare Enterprises), a medical device company that develops and markets products which reduce pain and increase the rate of healing through therapeutic, deep tissue heating, since May 2007. Previously, 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, from September 2000 to May 2007. 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.

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. Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990. Ms. Wakim serves as Chairman of the Compensation Committee and serves on the Audit Committee and the Nominating and Governance Committee.

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.

- 36 -

Index

Anthony J. Crisafio, a Certified Public Accountant, serves as an independent business consultant providing financial and operational advice to businesses and has done so since 1995. Additionally, Mr. Crisafio has served as the Chief Operating Officer of Cinema World, Inc. from 1989 until 1993 and was a partner with Ernst & Young from 1986 until 1989. Mr. Crisafio serves as the Chairman of the Audit Committee and serves on the Compensation Committee.

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 to his retirement in May 2007. Mr. Casabona’s responsibilities included strategic planning as well as executive oversight of the drilling operations in the continental United States and internationally. In 2008 Mr. Casabona assumed the title of 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.

Larry F. Mazza is President and Chief Executive Officer of MVB Financial Corporation 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 such position, Mr. Mazza served as Senior Vice President Retail Banking Manager & President & CEO for BB&T and its predecessors in West Virginia, where he was employed from June 1986 to March 2005. Mr. Mazza serves on the Nominating and Governance Committee and the Compensation Committee.

James M. Trimble serves as Managing Director and Chief Executive Officer of the parent and US subsidiaries of Grand Gulf Energy Limited, a public company traded on the Australian Exchange. In January 2005, Mr. Trimble founded Grand Gulf Energy Company LLC, an Exploration and Development company focused primarily on drilling in mature basins in Texas, Louisiana, and Oklahoma. Prior to founding Grand Gulf Energy, Mr. Trimble served as President, Chief Executive Officer and Chairman of the Board of TexCal Energy LLC from June 2002 through December 2004. From July 2000 to December 2001, Mr. Trimble was President and a member of the Board of Directors of Elysium Energy L.L.C., an exploration and production company. From 1983 to 2000, he served as Senior Vice President – Exploration and Production of Cabot Oil and Gas Company, a publicly held, mid-sized exploration and production company. Mr. Trimble serves on the Planning and Finance Committee and the Compensation Committee.

The Audit Committee of the Board of Directors is comprised of Directors Swoveland, Crisafio, Wakim and Casabona. The Board has determined that the Audit Committee is comprised entirely of independent directors as defined by the NASDAQ rule 4200(a) (15). Anthony J. Crisafio chairs the Audit Committee. All audit committee members qualify as audit committee financial experts.

- 37 -

Index

Item 11.

Executive Compensation

The Partnership does not have any directors or executives of its own. None of PDC's directors or executive officers receive any direct remuneration, compensation or reimbursement from the Partnership. These persons receive compensation solely from PDC. None of PDC’s compensation policies and practices that are available to key employees, executive officers or directors who act on behalf of the Partnership are reasonably likely to have a material 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. For more information on the Partnership’s compensation to the Managing General Partner, see Item 13, Certain Relationships and Related Transactions, and Director Independence, below.

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related StockholderMatters

The following table presents information as of December 31, 2009 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 63% of Total Partnership Interests (1)		Number of Units Beneficially Owned		Percentage of Total Units Outstanding			Percentage of Total Partnership Interests Beneficially Owned
		4,497.03
Petroleum Development Corporation (2) (3) (4)		-		8.00		0.18	%		0.11	%
Investor Partners beneficially owning 5% or more, of limited partner interests		-		-		-			-
Petroleum Development Corporation (2), Managing General Partner		-		-		-			37.00	%

(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, 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. [(8.00 units/4,497.03 units)*63% limited partnership ownership]

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.

- 38 -

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.

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 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 an oil and natural gas 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 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 the agreements.

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 is 0.052% of 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.

- 39 -

Index

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) (3)	$	185,000	$	-
Tax Fees (2)		9,000		23,000
Total fees	$	194,000	$	23,000

(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 condensed interim financial statements which accompany the Partnership’s Quarterly reports on Form 10-Q.

(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’s.

(3)

Since PwC became the Partnership’s independent registered public accounting firm on May 28, 2009, there were no audit fees paid to the firm during 2008. Audit fees paid during 2008 to the Partnership’s previous independent registered public accounting firm, Schneider Downs, was approximately $258,000.

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.

- 40 -

Index

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

10-12G/A

Amend 1

000-52787

12/24/2007

3.2

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

10-12G/A

Amend 1

000-52787

3.1

12/24/2007

10.2

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

10-12G/A

Amend 1

000-52787

10.2

12/24/2007

10.3

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

10-K

000-07246

03/04/2010

23.1

Consent of Ryder Scott Company, L.P., Petroleum Consultants

31.1

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

31.2

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

32.1

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

99.2

Report of Independent Petroleum Consultants−Ryder Scott Company, LP

- 41 -

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.

Rockies Region 2006 Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

March 31, 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	March 31, 2010
Richard W. McCullough	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	March 31, 2010
Gysle R. Shellum	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	March 31, 2010
R. Scott Meyers	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal accounting officer)

/s/ Kimberly Luff Wakim	Director	March 31, 2010
Kimberly Luff Wakim	Petroleum Development Corporation
	Managing General Partner of the Registrant

/s/ Anthony J. Crisafio	Director	March 31, 2010
Anthony J. Crisafio	Petroleum Development Corporation
	Managing General Partner of the Registrant

/s/ Jeffrey C. Swoveland	Director	March 31, 2010
Jeffrey C. Swoveland	Petroleum Development Corporation
	Managing General Partner of the Registrant

/s/ Joseph E. Casabona	Director	March 31, 2010
Joseph E. Casabona	Petroleum Development Corporation
	Managing General Partner of the Registrant

- 42 -

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Index to Financial Statements

Reports of Independent Registered Public Accounting Firms	F-2
	F-3

Balance Sheets - December 31, 2009 and 2008	F-4

Statements of Operations - For the Years Ended December 31, 2009 and 2008	F-5

Statements of Partners' Equity - For the Years Ended December 31, 2009 and 2008	F-6

Statements of Cash Flows - For the Years Ended December 31, 2009 and 2008	F-7

Notes to Financial Statements	F-8

Supplemental Oil and Gas Information - Unaudited	F-27

F-1

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of the Rockies Region 2006 Limited Partnership,

In our opinion, the accompanying balance sheet and the related statements of operations, partners’ equity and cash flows present fairly, in all material respects, the financial position of Rockies Region 2006 Limited Partnership (the “Partnership”) at December 31, 2009 and the results of its operations and its cash flows for the year 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 audit. We conducted our audit 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 audit provides 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

March 31, 2010

F-2

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Report of Independent Registered Public Accounting Firm

To the Partners

Rockies Region 2006 Limited Partnership:

We have audited the accompanying balance sheet of Rockies Region 2006 Limited Partnership as of December 31, 2008 and the related statements of operations, partners’ equity and cash flows for the year then ended. 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 audit.

We conducted our audit 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. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal controls over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rockies Region 2006 Limited Partnership as of December 31, 2008 and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Schneider Downs & Co., Inc.

Pittsburgh, Pennsylvania

March 31, 2009

F-3

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Balance Sheets

As of December 31, 2009 and 2008

Assets	2009			2008

Current assets:
Cash and cash equivalents	$	5,278		$	203,462
Accounts receivable		1,022,281			1,173,324
Oil inventory		44,266			45,750
Due from Managing General Partner-derivatives		1,414,982			5,772,399
Due from Managing General Partner-other, net		413,982			2,372,921
Total current assets		2,900,789			9,567,856


Oil and gas properties, successful efforts method, at cost		97,856,261			97,606,701
Less: Accumulated depreciation, depletion and amortization		(35,009,030	)		(25,706,395	)
Oil and gas properties, net		62,847,231			71,900,306

Due from Managing General Partner-derivatives		1,084,358			2,009,629
Total noncurrent assets		63,931,589			73,909,935


Total Assets	$	66,832,378		$	83,477,791


Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	129,730		$	206,320
Due to Managing General Partner-derivatives		1,180,416			-
Total current liabilities		1,310,146			206,320

Due to Managing General Partner-derivatives		3,221,492			300,410
Asset retirement obligations		1,039,044			775,083
Total liabilities		5,570,682			1,281,813

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		17,730,814			25,476,495
Limited Partners - 4,497.03 units issued and outstanding		43,530,882			56,719,483
Total Partners' equity		61,261,696			82,195,978

Total Liabilities and Partners' Equity	$	66,832,378		$	83,477,791

See accompanying notes to financial statements.

F-4

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Statements of Operations

For the Years Ended December 31, 2009 and 2008

	2009			2008
Revenues:
Natural gas and oil sales	$	10,928,207		$	29,959,247
Commodity price risk management (loss) gain, net		(2,739,342	)		9,141,981
Total revenues		8,188,865			39,101,228

Operating costs and expenses:
Natural gas and oil production costs		3,511,341			5,135,146
Direct costs - general and administrative		562,310			673,877
Depreciation, depletion and amortization		9,302,635			11,496,628
Exploratory dry hole costs		58,826			85,236
Loss on impairment of oil and gas properties		-			3,839,197
Accretion of asset retirement obligations		22,472			38,362
Total operating costs and expenses		13,457,584			21,268,446

(Loss) income from operations		(5,268,719	)		17,832,782

Gain on sale of oil and gas properties		-			120,000
Interest expense		(5,892	)		-
Interest income		7,418			85,460

Net (loss) income	$	(5,267,193	)	$	18,038,242

Net (loss) income allocated to partners	$	(5,267,193	)	$	18,038,242
Less: Managing General Partner interest in net (loss) income		(1,948,861	)		6,674,150
Net (loss) income allocated to Investor Partners	$	(3,318,332	)	$	11,364,092

Net (loss) income per Investor Partner unit	$	(738	)	$	2,527

Investor Partner units outstanding		4,497.03			4,497.03

See accompanying notes to financial statements.

F-5

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Statements of Partners' Equity

For the Years Ended December 31, 2009 and 2008

	Investor Partners			Managing General Partner			Total

Balance, December 31, 2007	$	61,844,776		$	28,539,072		$	90,383,848

Distributions to partners		(16,489,385	)		(9,736,727	)		(26,226,112	)

Net income		11,364,092			6,674,150			18,038,242

Balance, December 31, 2008		56,719,483			25,476,495			82,195,978

Distributions to partners		(9,870,269	)		(5,796,820	)		(15,667,089	)

Net loss		(3,318,332	)		(1,948,861	)		(5,267,193	)

Balance, December 31, 2009	$	43,530,882		$	17,730,814		$	61,261,696

See accompanying notes to financial statements.

F-6

Index

ROCKIES REGION 2006 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	$	(5,267,193	)	$	18,038,242
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
Loss on impairment of oil and gas properties		-			3,839,197
Depreciation, depletion and amortization		9,302,635			11,496,628
Accretion of asset retirement obligations		22,472			38,362
Gain on sale of oil and gas properties		-			(121,335	)
Unrealized loss (gain) on derivative transactions		9,384,186			(8,561,788	)
Exploratory dry hole costs		58,826			85,236
Changes in operating assets and liabilities:
Decrease in accounts receivable		151,043			2,315,436
Decrease (increase) in oil inventory		1,484			(45,750	)
Decrease in accounts payable and accrued expenses		(76,590	)		(392,070	)
Decrease (increase) in due from Managing General Partner, Net		1,958,939			(1,343,709	)
Net cash provided by operating activities		15,535,802			25,348,449

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(156,992	)		(222,685	)
Proceeds from sale of leaseholds		-			120,000
Proceeds from sale of equipment		40,048			-
Proceeds from Colorado sales tax refund related to capital purchases		50,047			-
Net cash used in investing activities		(66,897	)		(102,685	)

Cash flows from financing activities:
Distributions to Partners		(15,667,089	)		(26,226,112	)
Net cash used in financing activities		(15,667,089	)		(26,226,112	)

Net decrease in cash and cash equivalents		(198,184	)		(980,348	)
Cash and cash equivalents, beginning of year		203,462			1,183,810
Cash and cash equivalents, end of year	$	5,278		$	203,462

Supplemental cash flow information:
Cash payments for:
Interest	$	5,892		$	-

Supplemental disclosure of non-cash activity:
Change in Due to Managing General Partner−other, net, related to purchases of properties and equipment		-			1,068,657
Change in asset retirement obligation, with a corresponding increase to natural gas and oil properties		241,489			(38,931	)

See accompanying notes to financial statements.

F-7

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

Note 1 – General

Rockies Region 2006 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 oil and natural gas properties. Business operations of the Partnership commenced upon closing of an offering for the private placement 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”) 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 manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.

As of December 31, 2009, there were 2,019 Investor Partners. Petroleum Development Corporation has been designated the Managing General Partner of the Partnership and has a 37% Managing General Partner ownership in the Partnership. Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 63% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 37% to the Managing General Partner. Through December 31, 2009, the Managing General Partner has repurchased 8.0 units of Partnership interests from Investor Partners at an average price of $10,115 per unit.

The following table presents Partnership formation and organizational information through the completion of the drilling phase on September 4, 2007:

RR06LP Limited Partnership Information	Date	Number of Partners		Number of Partner Units					Equity Percentage			Amount (millions)
RR06LP Limited Partnership Information	Date	Number of Partners		Additional General Partner Units			Limited Partner Units		Equity Percentage			Amount (millions)

West Virginia Limited Partnership Formation	July 20, 2006
Limited Partnership Termination Date	December 31, 2056

Private Placement of Securities and Funding	September 7, 2006
Investor Partners (1) Unit Cost: $20,000			2,022		4,449.78			47.25		63.00	%	$	89.9
PDC, Managing General Partner										37.00	%		38.9
Total funding													128.8
Syndication costs paid to third-party brokers													(9.1	)
Management Fee Paid to PDC													(1.3	)
Net funding available for drilling activities										100.00	%	$	118.4

Conversion of additional General Partners to Limited Partners	September 4, 2007				(4,449.78	)		4,449.78
Limited Partnership Units after Conversion					-			4,497.03

(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 is 0.052% of 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-8

Index

ROCKIES REGION 2006 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. The statements do not include any assets, liabilities, revenues or expenses attributable to any of the partners' other activities.

Reclassifications. Certain reclassifications have been made to prior period financial statements to conform to the current year presentation, with no effect on previously reported net income or Partners’ Equity. For more information on these reclassifications, see Note 3, Transactions with Managing General Partner and Affiliates.

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 and limits its 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 oil and natural gas production. The Partnership sells substantially all of its oil and natural gas to customers who purchase oil and natural gas from other partnerships managed by the Partnership’s Managing General Partner. Inherent to the Partnership’s industry is the concentration of oil and natural gas 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.

F-9

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

Due from (to) Managing General Partner – Other, net

The Managing General Partner transacts business on behalf of the Partnership. Other than undistributed oil and natural gas revenues by PDC to the Partnership and the Partnership’s portion of unexpired derivatives instruments, which are included in separate balance sheet captions, all other unsettled transactions with PDC and its affiliates are recorded net on the balance sheet under the caption “Due from (to) Managing General Partner – Other, net.” For more information regarding transactions with the Managing General Partner, see Note 3, Transactions with Managing General Partner and Affiliates. In 2008 the Partnership incurred additional drilling costs of $1,068,657 in excess of drilling advances paid to the Managing General Partner. This amount has been recorded as a liability in the account “Due from (to) Managing General Partner - other” and will be funded by a reduction in future distributable cash flows. No Partnership distributable cash flows for the year 2009 were retained for the payment of this obligation.

Commitments and Contingencies

On behalf of and to the benefit of the Partnership and other partnerships for which PDC serves as Managing General Partner, the Managing General Partner maintains a margin deposit with counterparties on outstanding derivative contracts and also maintains bonds in the form of certificates of deposit for the plugging and abandoning of wells as required by various governmental agencies. Since these deposits represent general obligations of the Managing General Partner and are not specific and identifiable as obligations of the Partnership, no amounts are recorded by the Partnership related to these contingent deposits.

Inventories

Oil inventories are stated at the lower of average lifting cost or market, and are removed at carrying value.

Natural Gas and Oil Properties

The Partnership accounts for its oil and natural gas properties (the “Properties”) under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells 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 Oil and Gas 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 oil and natural gas 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.

F-10

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

Cumulative in-progress exploratory well drilling costs are initially capitalized as “Suspended well costs” until the well’s productive status becomes known. If the well is determined to be economically nonproductive, the well’s capitalized costs are expensed, as are any subsequent costs to plug, abandon and environmentally remediate the well site. The Partnership’s three D Sand and J Sand formations Wattenberg Field exploratory wells, one Nesson formation Coteau Field exploratory well and one Nesson formation Wildcat Field exploratory well were determined to be economically unproductive and declared dry holes during 2007 and were plugged and abandoned, or sold, during 2007 and 2008; accordingly, the initial cumulative costs to drill the well as well as subsequent costs were charged to the line caption, “Exploratory dry hole costs” on the Partnership’s statements of operations. Since inception through December 31, 2009, the Partnership recorded $8.3 million in exploratory dry hole costs. The Partnership will conduct no future exploratory drilling activities.

The Partnership accounts for the impairment of long-lived assets by periodically assessing its proved natural gas and oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Partnership reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of oil and natural gas. 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 oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed their fair value. 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 incurred no additional impairment losses as a result of this review. The Partnership incurred impairment losses during 2008 of $3.8 million on its Bailey and Carter Fields proved oil and natural gas properties. Since there were no additional impairments recognized during 2009, the Partnership’s has recorded total impairments of $13.4 million since the Partnership’s inception, for these two fields.

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, collects a price, 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.

F-11

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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.

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 oil and natural gas. 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.

F-12

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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 oil and natural gas 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 U.S. Generally Accepted Accounting Principles, or GAAP. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; instead, the FASB will issue Accounting Standards Updates. Accounting Standards Updates will not be authoritative in their own right as they will only serve to update the Codification. These changes and the Codification itself do not change GAAP. Effective July 1, 2009, the Partnership adopted the Codification. Other than the manner in which new accounting guidance is referenced, the adoption of the Codification did not have any impact on the Partnership’s financial statements.

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.

Fair Value Measurements and Disclosures

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.

In February 2008, the FASB delayed by one year (to January 1, 2009) the fair value measurements and disclosure requirements 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 January 1, 2009, adoption of the fair value measurements and disclosure requirements for the Partnership’s nonfinancial assets and liabilities did not have a material impact on the Partnership’s financial statements. See Note 4, Fair Value Measurements.

F-13

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

Derivatives and Hedging Disclosures

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

Oil and Gas Reserve Estimation and Reporting

In January 2009, the SEC published its final rule regarding the modernization of oil and gas reporting, which modifies the SEC’s reporting and disclosure rules for oil and gas 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 oil and gas 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 $195,000.

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 are not expected to have a material impact on the Partnership’s financial statements when adopted in 2010.

F-14

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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 is evaluating the impact that adoption will have on the Partnership’s financial statements and related disclosures.

Subsequent Events

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

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 fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the captions “Due from Managing General Partner–derivatives,” in the case of net unrealized gains or “Due to Managing General Partner–derivatives,” in the case of net unrealized losses. The fair value of derivative instruments previously reported at December 31, 2008, in which individual contracts held by each counterparty were aggregated, or netted, for determining presentation as a net asset, or net liability of the Partnership, have been reclassified to conform to the current year individual contract presentation methodology.

F-15

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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 (1)	$	1,073,920		$	2,382,497
Commodity Price Risk Management, Realized Gains		963,873			2,281,462
Other (2) (3)		(1,623,811	)		(2,291,038	)
Total Due from Managing General Partner - other, net	$	413,982		$	2,372,921

(1)

Reclassification. Undistributed natural gas and oil sales revenues as of December 31, 2008 in the amount of $2,382,497 have been reclassified from “Accounts Receivable” to “Due from Managing General Partner – other, net” to conform to current year presentation.

(2)

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

(3)

In 2008, the Partnership incurred additional drilling costs of $1,068,657 in excess of drilling advances paid to the Managing General Partner. This amount has been recorded as a liability in the account “Due from (to) Managing General Partner - other” and will be funded by a reduction in future distributable cash flows. No Partnership distributable cash flows for the year 2009 were retained for the payment of this obligation.

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 $195,000 including legal fees of approximately $16,000 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. See Note 6, Partners’ Equity and Cash Distributions.

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)	$	2,749,749	$	3,054,590
Gathering, compression and processing fees (2)		338,508		297,848
Direct costs - general and administrative (3)		562,310		673,877
Cash distributions (4) (5)		5,808,232		9,736,727

(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.

F-16

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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.

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.

F-17

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

(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 63% to the Investors Partners and 37% to the Managing General Partner. Investor Partner cash distributions include $11,412 and $11,261 during the years 2009 and 2008, respectively, related to equity cash distributions on Investor Partner units repurchased by the Managing General Partner. 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 a non-recurring item. 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:

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.

F-18

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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	$	-		$	7,782,028		$	7,782,028
Total assets		-			7,782,028			7,782,028

Liabilities:
Basis protection derivative contracts		-			(300,410	)		(300,410	)
Total liabilities		-			(300,410	)		(300,410	)

Net asset	$	-		$	7,481,618		$	7,481,618

As of December 31, 2009
Assets:
Commodity based derivatives	$	1,094,091		$	1,405,249		$	2,499,340
Total assets		1,094,091			1,405,249			2,499,340

Liabilities:
Commodity based derivatives		(90,257	)		(296,710	)		(386,967	)
Basis protection derivative contracts		-			(4,014,941	)		(4,014,941	)
Total liabilities		(90,257	)		(4,311,651	)		(4,401,908	)

Net asset (liability)	$	1,003,834		$	(2,906,402	)	$	(1,902,568	)

F-19

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

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	$	7,481,618		$	(1,080,170	)
Changes in fair value included in statement of operations line item:
Commodity price risk management (loss) gain, net		(3,743,176	)		9,141,981
Settlements		(6,644,844	)		(580,193	)
Fair value, net (liability) asset end of year	$	(2,906,402	)	$	7,481,618

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) gain, net	$	(4,338,505	)	$	-

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 December 31, 2009, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 3,740,606 MMbtu of natural gas and 62,934 Bbls of oil. Partnership policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

The Managing General Partner uses oil and natural gas 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.

F-20

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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

F-21

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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

		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	$	1,414,982		$	5,772,399

Non Current
Commodity contracts	Due from Managing General Partner-derivatives		1,084,358			2,009,629

Total Derivative Assets			2,499,340			7,782,028


Derivative Liabilities:
Current
Commodity contracts	Due to Managing General Partner-derivatives		(92,588	)		-

Basis protection contracts	Due to Managing General Partner-derivatives		(1,087,828	)		-

Non Current
Commodity contracts	Due to Managing General Partner-derivatives		(294,379	)		-

Basis protection contracts	Due to Managing General Partner-derivatives		(2,927,113	)		(300,410	)


Total Derivative Liabilities			(4,401,908	)		(300,410	)

Net fair value of derivative instruments - (liability) asset		$	(1,902,568	)	$	7,481,618

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

The following table presents 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 Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total			Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total

Commodity price risk management, net
Realized gains (losses)	$	5,772,392		$	872,452		$	6,644,844		$	(1,080,170	)	$	1,660,363	$	580,193
Unrealized (losses) gains		(5,772,392	)		(3,611,794	)		(9,384,186	)		1,080,170			7,481,618		8,561,788
Total commodity price risk management (loss) gain, net	$	-		$	(2,739,342	)	$	(2,739,342	)	$	-		$	9,141,981	$	9,141,981

F-22

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

Note 6 - Partners’ Equity and Cash Distributions

Partners’ Equity

A 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 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		63	%		37	%
Commodity price risk management gain (loss)		63	%		37	%
Sale of productive properties		63	%		37	%
Sale of equipment		63	%		37	%
Interest income		63	%		37	%

Partnership Operating Costs and Expenses:
Natural gas and oil production and well operations costs (a)		63	%		37	%
Depreciation, depletion and amortization expense		63	%		37	%
Accretion of asset retirement obligations		63	%		37	%
Direct costs - general and administrative (b)		63	%		37	%

(a)

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

(b)

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

Unit Repurchase Provisions

Beginning in May 2010, the third anniversary of the date of the first Partnership distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units. 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. In addition to the unit repurchase program, individual investor partners periodically offer and PDC repurchases, units on a negotiated basis before the third anniversary of the date of the first cash distribution.

Cash Distributions

The Agreement requires the Managing General Partner to distribute cash available for distribution not 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 63% to the Investor Partners and 37% to the Managing General Partner. Cash distributions began in May 2007. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:

F-23

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

	Year Ended December 31,
	2009		2008

Cash distributions	$	15,667,089	$	26,226,112

Distributions to Partners in 2009 were impacted by a non-recurring item which was the Partnership’s payment to the Managing General Partner for royalty settlement costs of approximately $0.2 million which decreased distributions during the period. This amount had been previously accrued by the Partnership in “Due from (to) Managing General Partner – other, net.” For more information on the Colorado Royalty Settlement, see Note 9, Commitments and Contingencies.

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
Shell Trading (US) Company (“STUSCO”)		11	%		10	%
DCP Midstream LP (“DCP”)		13	%		12	%
Teppco Crude Oil, LP (“Teppco”)		2	%		33	%
Williams Production RMT (“Williams”),		35	%		45	%
Suncor Energy (USA) Inc. (“Suncor”)		38	%		−

Concentration of Credit Risk. A significant portion of the Partnership’s liquidity is concentrated in derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing oil and natural gas. These arrangements expose the Partnership to credit risk of nonperformance by the counterparty to the contracts. The Managing General Partner primarily uses financial institutions as counterparties to its derivative contracts, who hold the majority of the Managing General Partner’s derivative assets. The Managing General Partner has evaluated the credit risk of default from counterparties holding its derivative assets, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation, the Partnership has determined that the impact of counterparty non-performance on the fair value of the Partnership’s derivative instruments is not material. As of December 31, 2009, no adjustment for credit risk was recorded by the Partnership. Furthermore, while the Managing General Partner believes these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

F-24

Index

ROCKIES REGION 2006 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 oil and natural gas properties.

	Year Ended December 31,
	2009		2008

Balance at beginning of year	$	775,083	$	775,652
Revisions in estimated cash flows		241,489		(38,931	)
Accretion expense		22,472		38,362
Balance at end of year	$	1,039,044	$	775,083

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 Oil and Gas Information – Unaudited, Costs Incurred in Oil and Natural Gas 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 $195,000 including associated legal costs of approximately $16,000. This entire settlement of $178,788 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.

Other. On December 8, 2008, the Managing General Partner received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment, related to the stormwater permit for the Garden Gulch Road. The Managing 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 eight users of the road based upon their respective usage. The Partnership’s Grand Valley Field wells are located in this Basin. For information regarding the number of Partnership wells located in this field, see Supplemental Oil and Gas Information – Unaudited, Costs Incurred in Oil and Natural Gas 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. 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.

F-25

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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

F-26

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Supplemental Oil and Gas Information - Unaudited

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

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

The Partnership is engaged solely in oil and natural gas activities, all of which are located in the continental United States. Drilling operations began upon funding in September 2006 and all funds were advanced to the Managing General Partner as of December 31, 2006, for all planned drilling and completion activities. The Partnership owns an undivided working interest in 91 gross (89.7 net) producing natural gas and oil wells in the following areas:

63 wells located in the Wattenberg Field within the Denver-Julesburg (“DJ”) Basin, north and west of Denver, Colorado;

23 wells located in the Grand Valley Field within the Piceance Basin, situated near the western border of Colorado;

three wells located in the Bailey Field located in the western North Dakota Williston Basin area and

two wells located in the Carter Field located in western North Dakota Williston Basin area.

In addition to the 91 wells mentioned above, the Partnership participated in one developmental well (1.0 net) that was evaluated as commercially unproductive and declared to be developmental dry hole and five exploratory wells (5.0 net) that were evaluated as commercially unproductive and declared to be exploratory dry holes. An exploratory well is one which is drilled in an area where there has been no oil or natural gas production, or a well which is drilled to a previously untested or non-producing zone in an area where there are wells producing from other formations. In accordance with successful efforts oil and natural gas accounting requirements, the Partnership charged all costs associated to these exploratory dry holes to the line caption, “Exploratory dry hole costs” in the Partnership’s statements of operations. For the years ended December 31, 2009 and 2008, these costs, which represent final well abandonment and site environmental remediation expenditures, were approximately $0.1 million, for each year.

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	$	657,597		$	657,425
Development costs		97,198,664			96,949,276
Oil and gas properties, successful efforts method, at cost		97,856,261			97,606,701
Less: Accumulated depreciation, depletion and amortization		(35,009,030	)		(25,706,395	)
Oil and gas properties, net	$	62,847,231		$	71,900,306

Included in Development Costs are the estimated costs associated with the Partnership’s asset retirement obligations discussed in Note 8, Asset Retirement Obligations and one Wattenberg Field developmental dry hole costs, consistent with the successful efforts oil and gas accounting method.

F-27

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Supplemental Oil and Gas Information - Unaudited

Costs incurred in oil and gas property exploration and development are presented below:

	Year ended December 31,
	2009		2008

Leasehold costs	$	172	$	23,634
Developmental costs		249,388		1,182,472
Exploration costs		58,826		85,236
Total costs incurred	$	308,386	$	1,291,342

Development costs include costs, net of sales and refund proceeds, incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, recompletions and to provide facilities to extract, treat, gather and store oil and gas. During 2009, the Partnership realized proceeds for the sale of surplus Carter Field equipment and State of Colorado sales tax refunds related to tangible well equipment purchases during previous-year drilling operations, totaling approximately $0.1 million for these two items. Development costs also include “Revisions to estimated cash flows” associated to the Partnership’s asset retirement obligations costs as discussed previously in Note 8, Asset Retirement Obligation. Exploration costs include plugging, abandonment, and final reclamation costs associated to the Partnership’s exploratory dry holes.

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. 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.

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 2012 or later, generally occur five to ten years after initial well drilling. Currently, the Partnership expects recompletion activities to be completed through approximately 2015. 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.

F-28

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Supplemental Oil and Gas Information - Unaudited

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

	Price
	Oil (per Bbl)		Gas (per Mcf)
2009	$	54.00	$	3.14
2008		37.28		4.71

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		24,343			1,803			35,161
Revisions of previous estimates		(1,938	)		(482	)		(4,830	)
Production		(2,532	)		(149	)		(3,426	)
Proved reserves, December 31, 2008		19,873			1,172			26,905

Revisions of previous estimates		(1,948	)		22			(1,816	)
Production		(1,849	)		(106	)		(2,485	)
Proved reserves, December 31, 2009		16,076			1,088			22,604



Proved Developed Reserves, as of:

December 31, 2008		16,820			596			20,396
December 31, 2009		13,182			510			16,242


Proved Undeveloped Reserves, as of:

December 31, 2008		3,053			576			6,509
December 31, 2009		2,894			578			6,362

Definitions used throughout Supplemental Oil and Gas 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 oil and natural gas reserves experienced an upward revision of previous estimates of 22 MBbls of oil and downward revision of previous estimates of 1,948 MMcfs of natural gas. This net revision is the result of revisions to proved developed producing reserves that include an increase of approximately 20 MBbls of oil and a decrease of 1,789 MMcfs of natural gas, in addition to a revision of proved undeveloped reserves amounting to an increase of approximately 2 MBbls of oil and a decrease of 159 MMcfs of natural gas. The net downward revision to proved developed producing oil and natural gas reserves was primarily due to reduced economics resulting from significantly lower twelve-month average natural gas prices that was partially offset by improved Bailey, Carter and Wattenberg Field’s oil and natural gas operational asset performance and higher oil prices. 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.

F-29

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Supplemental Oil and Gas Information - Unaudited

At December 31, 2008, the Partnership’s estimated proved oil and natural gas reserves experienced a net downward revision of previous estimates of 482 MBbls of oil and 1,938 MMcfs of natural gas. This net revision is the result of a downward revision of proved developed producing reserves amounting to approximately 392 MBbls of oil and 1,940 MMcfs of natural gas, accompanied by a net downward revision of proved undeveloped reserves amounting to an approximately 90 MBbls downward revision of oil partially offset by an approximately 2 MMcfs upward revision of natural gas. The downward revision to proved developed producing reserves and proved undeveloped reserves was primarily due to reduced economics resulting from significantly lower year-end oil and natural gas prices and higher per-well operating costs at December 31, 2008.

F-30

Rockies Region 2006 Limited Partnership - FORM 10-K - March 31, 2010

Attached files

Rockies Region 2006 Limited Partnership Reports