10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

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

For the fiscal year ended December 31, 2011

or

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

FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number  000-53201

Rockies Region 2007 Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia	26-0208835
(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 R

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes R  No £

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

Indicate by check mark 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. R

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

Large accelerated filer     £	Accelerated filer  £
Non-accelerated filer £	Smaller reporting company R

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

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 Registrant's securities. Therefore, there is no aggregate market value.

As of February 29, 2012, the Partnership had 4,470 units of limited partnership interest and no units of additional general partnership interest outstanding.

ROCKIES REGION 2007 LIMITED PARTNERSHIP

2011 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

		Page
	Part I
	Additional Information, Units of Measurement	1
	Special Note Regarding Forward-Looking Statements	2
Item 1	Business	3
Item 1A	Risk Factors	20
Item 1B	Unresolved Staff Comments	20
Item 2	Properties	20
Item 3	Legal Proceedings	20
Item 4	Mine Safety Disclosures	20
	Part II
Item 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6	Selected Financial Data	23
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	36
Item 8	Financial Statements and Supplementary Data	36
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	36
Item 9A	Controls and Procedures	36
Item 9B	Other Information	37
	Part III
Item 10	Directors, Executive Officers and Corporate Governance	38
Item 11	Executive Compensation	42
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	43
Item 13	Certain Relationships and Related Transactions, and Director Independence	43
Item 14	Principal Accountant Fees and Services	44
	Part IV
Item 15	Exhibits, Financial Statement Schedules	45
Signatures		49

PART I

WHERE YOU CAN FIND ADDITIONAL INFORMATION

The Rockies Region 2007 Limited Partnership (“Partnership” or “Registrant”) 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 U.S. Securities and Exchange Commission ("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 0001407805. 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.

UNITS OF MEASUREMENT

The following presents a list of units of measurement used throughout the document.

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

Btu - British thermal unit.

MBbls - One thousand barrels of crude oil or NGLs.

Mcf - One thousand cubic feet of natural gas volume.

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

MMBtu - One million British thermal units.

MMcf - One million cubic feet of natural gas volume.

MMcfe - One million cubic feet of natural gas equivalent.

1

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding Rockies Region 2007 Limited Partnership's business, financial condition and results of operations. Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements include: estimated natural gas, natural gas liquids ("NGLs"), and crude oil production and reserves; additional development plans; future cash flows and anticipated liquidity; anticipated capital expenditures; the adequacy of the Managing General Partner's casualty insurance coverage; the effectiveness of the Managing General Partner's derivative policies in achieving the Partnership's risk management objectives; and the Managing General Partner's strategies, plans and objectives.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

• changes in production volumes and worldwide demand;

• volatility of commodity prices for natural gas, NGLs and crude oil;the impact of governmental fiscal terms and/or regulations, including changes in environmental laws, the regulation and enforcement related to those laws and the costs to comply with those laws, as well as other regulations;

• changes in estimates of proved reserves;

• inaccuracy of reserve estimates and expected production rates;

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

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

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

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

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

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

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

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

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

• the timing and receipt of necessary regulatory permits;

• competition in the oil and gas industry;

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

• the effect of natural gas derivative activities;

• the cost of pending or future litigation;

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

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

Further, the Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this report and the Partnership's other filings with the SEC for further information on risks and uncertainties that could affect the Partnership's business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement.

2

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 crude oil wells located in Colorado from which the Partnership produces and sells natural gas, NGLs and crude oil. The Partnership was organized and began operations in 2007 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”) and the Managing General Partner. The Investor Partners own 63% of the Partnership's capital, or equity interests. PDC, the Managing General Partner, a Nevada Corporation, 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. 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. The Partnership expended substantially all of the capital raised in the offering for the initial drilling and completion of the Partnership's wells.

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

The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership's wells are depleted or becomes uneconomical to produce, at which time that well may be sold or plugged, reclaimed and abandoned. The Partnership's maximum term of existence extends through December 31, 2057, 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.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, which began in the fall of 2010 and extends through 2013, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of the particular partnership other than those held by PDC or its affiliates (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership. For additional information regarding PDC's intention to pursue acquisitions of PDC sponsored partnerships, refer to prior disclosure included in PDC's filings made with the SEC and presentations on PDC's website. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnership units held by the non-affiliated investor partners of such limited partnership. Consummation of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and each non-affiliated investor partner will receive the right to receive a cash payment for their limited partnership units in that partnership and will no longer participate in that partnership's future earnings or the Partnership's economic benefit.

3

During 2010 and 2011, PDC purchased twelve partnerships for the aggregate amount of $107.7 million. The feasibility and timing of any future cash purchase offer by PDC to any additional partnership, including this Partnership, depends on that partnership's suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership's well inventory; favorability of economics for the Wattenberg Field additional development, including commodity prices; and SEC reporting compliance status and timing and ability to achieve all necessary SEC approvals required to commence a merger and repurchase offer. On December 21, 2011, PDC and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to 11 partnership repurchases completed by mergers in 2010 and 2011.  The action was filed in U.S. District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp., et al.  PDC was managing general partner for each of these partnerships and the mergers were each approved by a majority of the non-PDC partnership units. The complaint includes allegations that the proxy statements issued in connection with the mergers were inadequate, and a breach of fiduciary duty.  On February 10, 2012, PDC filed a motion to dismiss or in the alternative, stay the action.  PDC believes the suit is without merit and intends to defend vigorously. There is no assurance that any potential proposed repurchase offer to any other of PDC's various public limited partnerships, including this Partnership, will occur.

Business Strategy

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

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

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 completed, and production operations are currently being conducted with regard to each of the Partnership's productive wells.

PDC, in accordance with the D&O Agreement, is the named operator of record of the Partnership's wells and may, in certain circumstances, provide equipment and supplies, perform salt water disposal 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, production 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 cash available for distributions is insufficient to make full payment, PDC defers the collection of operating expenses until such time as scheduled expenses may be offset against future Partnership cash available for distributions. In such instances, the Partnership records a liability to PDC. The Managing General Partner considers the cash available for distributions to be the Partnership's net cash flows provided by operating activities less any net cash used in capital activities.

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

4

Areas of Operations

The Partnership's operating areas are profiled as follows:

Wattenberg Field, DJ Basin, Colorado. Located north and east of Denver, Colorado, the Partnership's wells in this field exhibit production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. Although natural gas is the primary hydrocarbon produced, many wells also produce NGLs and/or crude oil. Of the Partnership's 75 wells drilled in the Wattenberg Field, 69 were initially completed and currently produce from the Codell formation. Of these Codell formation wells, 67 were also completed in the shallower Niobrara formation. In addition to the shallower formation well completions, the Partnership also completed wells, including one Dakota formation well and five J-Sand formation wells, that currently produce from deeper formations. The Partnership's development wells in this area are generally 7,000 to 8,000 feet in depth. Well spacing ranges from 20 to 40 acres per well.

Piceance Basin, Colorado. Located near the western border of Colorado, the Partnership's 24 wells in this field have also exhibited production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. These wells generally produce natural gas along with small quantities of crude oil. In addition to the Piceance Basin's producing wells, one additional well (1.0 net) drilled in the field was declared to be a developmental dry hole due to downhole mechanical failure and was subsequently plugged and abandoned. The majority of the Partnership's development wells drilled in the area were drilled directionally from multi-well pads ranging from two to eight or more wells per drilling pad. The primary drilling targets were multiple sandstone reservoirs in the Mesa Verde formation and well depth ranges from 7,000 to 9,500 feet. Well spacing is approximately 10 acres per well.

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 natural gas and crude oil properties, in accordance with standards generally accepted in the industry, through the record title held in the Partnership's name, of each Partnership well's working interest. The Partnership's properties are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The Managing General Partner is not aware of any additional burdens, liens or encumbrances customary to the industry, if any, which may materially interfere with the commercial use of the properties. Provisions of the Agreement generally relieve PDC from errors in judgment with respect to the waiver of title defects.

Drilling and Other Development Activities

Natural Gas and Crude Oil Properties. The Partnership's properties (the “Properties”) consist of a working interest in the well bore in each well drilled by the Partnership. The Partnership drilled 100 wells (98.9 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 September 2008 when the last of the Partnership's 99 productive wells were connected to sales and gathering lines. One Piceance Basin well (1.0 net) was declared to be a developmental dry hole due to down-hole mechanical failure and was subsequently plugged and abandoned. No exploratory drilling activity was conducted on behalf of the Partnership. The 100 wells discussed above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been expended.

The following table presents the number of the Partnership's productive wells by operating field as of December 31, 2011 and 2010. Productive wells consist of producing wells and wells capable of producing natural gas and/or NGLs and crude oil in commercial quantities.

	Productive Natural Gas Wells
	2011		2010
Location	Gross	Net	Gross	Net
Piceance Basin	24.0	24.0	24.0	24.0
Wattenberg Field	75.0	73.9	75.0	73.9
Total Productive Wells	99.0	97.9	99.0	97.9

5

Additional Development Plan. The Managing General Partner has prepared a plan for the Partnership's Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “Additional Development Plan”). The Additional Development Plan consists of the Partnership's refracturing of wells currently producing in the Codell formation and/or recompletion in the Niobrara or Codell formation which is currently not producing. Under the Additional Development Plan, the Partnership plans to initiate additional development activities during 2012. Refracturing activities consist of a second hydraulic fracturing treatment in a current production zone, while recompletion activities consist of an initial hydraulic fracturing treatment in a new production zone, all within an existing well bore.

Additional development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ten years after initial well drilling so that well resources are optimally utilized. This additional development would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to refracture or recomplete the individual wells and to determine the timing of any additional development activity. The timing of the refracturing or recompletion can be affected by the desire to optimize the economic return by additional development of the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership. On average, the production resulting from PDC's refracturings or recompletions have increased production; however, all refracturings or recompletions have not been economically successful and similar future refracturing or recompletion activities may not be economically successful. If the additional development work is performed, the Partnership will bear the direct costs of refracturing or recompletion, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from cash available for distributions. The Managing General Partner considers the cash available for distributions to be the Partnership's net cash flows provided by operating activities less any net cash used in capital activities.

The Limited Partnership Agreement (the “Agreement”) permits the Partnership to borrow funds or receive advances, from the Managing General Partner, its affiliates or unaffiliated persons, for Partnership activities. At this time, the Managing General Partner does not anticipate electing to fund the initial Additional Development Plan's well refracturings or recompletions, nor any subsequent refracturings or recompletions, through bank borrowing. In the event that the Partnership's refracturing or recompletion activities are funded in part through borrowing, potential cash available for distributions derived from production increases provided by this additional development of the Partnership's Wattenberg Field wells may not be sufficient to repay the Partnership's borrowing financial obligations, which will include principal and interest. Borrowings, if any, will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for loan repayment. However, any bank borrowings may be collateralized by the Partnership's assets and may restrict distributions as long as there is a balance due on any loan.

During the fourth quarter of 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing or recompletion costs. This program will materially reduce, up to 100%, cash available for distributions of the partnerships for a period of time not to exceed five years.

Current estimated costs for these well refracturings or recompletions are between $180,000 and $260,000 per activity. As of December 31, 2011, this Partnership had scheduled to complete 87 additional development opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $19.3 million and $21.8 million if all of the activities are performed. The Managing General Partner will continually evaluate the timing of commencing these additional development activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development. During the three months ended December 31, 2011, $650,000 was withheld from the Partnership's cash distributions pursuant to the Additional Development Plan. Cumulatively, $2,620,000 has been withheld from Partnership distributions through February 29, 2012, and resides in the Partnership's bank account.

Both the number and timing of the additional development activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing and recompletion costs and projected cash withholding, all scheduled Partnership additional development activity will be completed within a five year period. Any funds not used for refracturing, recompletion or other operational needs will be distributed to the Managing General Partner and Investor Partners based on their proportional ownership interest.

Implementation of the Additional Development Plan has and will continue to reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership's funds. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliatedinvestor partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Additional Development Plan. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated investor partners should depend upon the advice of their own tax advisors concerning the effects of the Additional Development Plan.

6

Proved Reserves

The Partnership's proved reserves are sensitive to future natural gas and crude oil sales prices and their effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property.

All of the Partnership's proved 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. All of the Partnership's proved reserves have been estimated by independent petroleum engineers.

The Managing General Partner has established a comprehensive process that governs the determination and reporting of the Partnership's proved reserves. As part of the Managing General Partner's internal control process, the Partnership's reserves are reviewed annually by an internal team composed of PDC reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data as well as production performance data. The review includes, but is not limited to, confirmation that reserve estimates (1) include all properties owned; (2) are based on proper working and net revenue interests; and (3) reflect reasonable cost estimates and field performance. The internal team compiles the reviewed data and forwards the data to an independent engineering 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 2011 and 2010 reserves. When preparing the Partnership's reserve estimates, the independent petroleum engineer did not independently verify the accuracy and completeness of information and data furnished by the Managing General Partner with respect to ownership interests, production volumes, 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 ensure that the reserve estimates were complete, determined by acceptable industry methods and to a level of detail the Managing General Partner deems appropriate. 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 internal 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 Chemical Refining Engineering with a minor in Petroleum Engineering and has over 30 years of experience in reservoir engineering. The individual is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and is a registered Professional Engineer in the State of Colorado.

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

• Proved developed reserves are those natural gas, NGLs and crude 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 refracturing or recompletion.

7

The following table provides information regarding the Partnership's estimated proved reserves. Reserves cannot be measured exactly, because reserve estimates involve judgments. The estimates must be 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 developed non-producing reserves consist entirely of reserves attributable to the Wattenberg Field's additional development. (See Item 1, Business−Operations, Drilling and Other Activities-Additional Development Plan on page 6). For additional information regarding the Partnership's reserves see the Net Proved Reserves section of the Supplemental Information provided with the financial statements included in this report. There were no proved undeveloped reserves that were developed in 2011.

	As of December 31,
	2011	2010
Proved Reserves
Natural Gas (MMcf)	18,415	20,291
Crude Oil and Condensate (MBbl)	879	1,125
NGLs (MBbl)	697	465
Total proved reserves (MMcfe)	27,871	29,831

8

The following tables present the Partnership's estimated proved reserves by type and by field.

	As of December 31, 2011
			Crude Oil and	Natural Gas
	Natural Gas	NGLs	Condensate	Equivalent
	(MMcf)	(MBbl)	(MBbl)	(MMcfe)	Percent
Proved developed
Piceance Basin	12,136	—	24	12,280	47	%
Denver-Julesburg (DJ) Basin: Wattenberg Field	5,568	651	752	13,986	53	%
Total proved developed	17,704	651	776	26,266	100	%
Proved undeveloped
Piceance Basin	—	—	—	—	—	%
Denver-Julesburg (DJ) Basin: Wattenberg Field	711	46	103	1,605	100	%
Total proved undeveloped	711	46	103	1,605	100	%
Proved reserves
Piceance Basin	12,136	—	24	12,280	44	%
Denver-Julesburg (DJ) Basin: Wattenberg Field	6,279	697	855	15,591	56	%
Total proved reserves	18,415	697	879	27,871	100	%

	As of December 31, 2010
			Crude Oil and	Natural Gas
	Natural Gas	NGLs	Condensate	Equivalent
	(MMcf)	(MBbl)	(MBbl)	(MMcfe)	Percent
Proved developed
Piceance Basin	14,801	—	38	15,029	72	%
Denver-Julesburg (DJ) Basin: Wattenberg Field	2,182	185	437	5,914	28	%
Total proved developed	16,983	185	475	20,943	100	%
Proved undeveloped
Piceance Basin	—	—	—	—	—	%
Denver-Julesburg (DJ) Basin: Wattenberg Field	3,308	280	650	8,888	100	%
Total proved undeveloped	3,308	280	650	8,888	100	%
Proved reserves
Piceance Basin	14,801	—	38	15,029	50	%
Denver-Julesburg (DJ) Basin: Wattenberg Field	5,490	465	1,087	14,802	50	%
Total proved reserves	20,291	465	1,125	29,831	100	%

Proved undeveloped reserves of 7,283 MMcfe were transferred to proved developed reserves in 2011 due to the reclassification of the Partnership's estimated Wattenberg refracture reserves as a result of the Managing General Partner's determination of the cost of a refracture becoming less significant as compared to the cost of drilling a new well.

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Production, Sales, Prices and Lifting Costs - By Field

The following table presents information regarding the Partnership's production volumes, natural gas, NGLs and crude oil sales, average sales price received and average production cost by field.

	Year Ended December 31,
	2011		2010
Production(1)
Natural gas (Mcf)
Piceance Basin	1,472,271		1,886,023
Denver-Julesberg (DJ) Basin: Wattenberg Field	232,442		357,863
Total Natural Gas	1,704,713		2,243,886
Crude Oil (Bbl)
Piceance Basin	3,325		5,763
Denver-Julesberg (DJ) Basin: Wattenberg Field	52,275		74,767
Total Crude Oil	55,600		80,530
NGLs (Bbl)
Denver-Julesberg (DJ) Basin: Wattenberg Field	21,356		29,497
Natural gas equivalent (Mcfe)
Piceance Basin	1,492,221		1,920,601
Denver-Julesberg (DJ) Basin: Wattenberg Field	674,228		983,447
Total natural gas equivalent	2,166,449		2,904,048
Natural Gas, NGLs and Crude Oil Sales
Natural gas sales
Piceance Basin	$	4,281,849	$	6,447,652
Denver-Julesberg (DJ) Basin: Wattenberg Field	797,545		1,394,974
Total natural gas sales	5,079,394		7,842,626
Crude oil sales
Piceance Basin	261,683		357,903
Denver-Julesberg (DJ) Basin: Wattenberg Field	4,631,132		5,503,224
Total crude oil sales	4,892,815		5,861,127
NGLs sales
Denver-Julesberg (DJ) Basin: Wattenberg Field	587,985		785,262
Natural gas, NGLs and crude oil sales
Piceance Basin	4,543,532		6,805,555
Denver-Julesberg (DJ) Basin: Wattenberg Field	6,016,662		7,683,460
Total natural gas, NGLs and crude oil sales	$	10,560,194	$	14,489,015
Average Sales Price (excluding realized gain on derivatives)
Natural gas (per Mcf)
Piceance Basin	$	2.91	$	3.42
Denver-Julesberg (DJ) Basin: Wattenberg Field	3.43		3.90
Average sales price natural gas, both fields	2.98		3.50
Crude Oil (per Bbl)
Piceance Basin	$	78.70	$	62.10
Denver-Julesberg (DJ) Basin: Wattenberg Field	88.59		73.60
Average sales price crude oil, both fields	88.00		72.78

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NGLs (per Bbl)
Denver-Julesberg (DJ) Basin: Wattenberg Field	$	27.53	$	26.62
Natural gas equivalent (per Mcfe)
Piceance Basin	$	3.04	$	3.54
Denver-Julesberg (DJ) Basin: Wattenberg Field	8.92		7.81
Average sales price natural gas equivalents, both fields	4.87		4.99
Average Production (Lifting) Cost (per Mcfe) (2)
Piceance Basin	$	1.76	$	1.73
Denver-Julesberg (DJ) Basin: Wattenberg Field	1.73		1.16
Average production cost, both fields	1.76		1.54

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

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

For more information concerning the Partnership's 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.

Natural Gas, NGLs and Crude Oil Sales

In accordance with the D&O Agreement, PDC markets the natural gas, NGLs and crude oil produced from the Partnership's wells primarily to other gas marketers, utilities, industrial end-users, other wholesale gas purchasers and petroleum refiners and marketers. The Managing General Partner generally sells the natural gas that the Partnership produces under contracts with indexed monthly pricing provisions. PDC does not charge an additional fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. This monthly charge is more fully described in the following: Item 1, Business −Reliance on the Managing General Partner, Provisions of the D&O Agreement. Virtually all of the Partnership's contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on 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 natural gas supplies. As a result, the Partnership's revenues from the sale of natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline. The Managing General Partner believes that the pricing provisions of the Partnership's natural gas contracts are customary in the industry. The Managing General Partner also has entered into financial derivatives in order to reduce the impact of possible price instability regarding the physical sales market. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations: Results of Operations - Commodity Price Risk Management, Net and Note 4, Derivative Financial Instruments, to the Partnership's financial statements included in this report.

In general, the Managing General Partner has been and expects to continue to be able to produce and sell natural gas and NGLs from the Partnership's wells without significant curtailment and at competitive prices. The Partnership does, however, experience limited curtailments from time to time due to pipeline maintenance and operating issues. Open access transportation through the country's interstate pipeline system gives us access to a broad range of markets. Whenever feasible, the Managing General Partner obtains access to multiple pipelines and markets from each of the Partnership's gathering systems, seeking the best available market for the Partnership's natural gas at any point in time.

The wells in the Partnership's Wattenberg Field and, to a significantly lesser extent, the Piceance Basin wells, produce crude oil as well as natural gas and NGLs. The Managing General Partner is currently able to sell all the crude oil that the Partnership can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of the Partnership's crude oil production. The Partnership's crude oil production is sold to purchasers at or near the Partnership's wells under both short and long-term purchase contracts with monthly pricing provisions.

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Transportation and Gathering

The Partnership's natural gas and NGLs are transported through the Managing General Partner's and third party gathering systems and pipelines, and the Partnership incurs processing, gathering and transportation expenses to move the Partnership's natural gas and related NGLs from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas transporters. While the Managing General Partner's ability to market the Partnership's natural gas and NGLs have been only infrequently limited or delayed, if transportation space is restricted or is unavailable, the Partnership's cash flow from the affected properties could be adversely affected. In order to meet pipeline specifications, the Managing General Partner is required, in some cases, to process the Partnership's natural gas before it can be transported. The Managing General Partner typically contracts with third parties in the Piceance Basin area of the Rocky Mountain Region for firm transportation of the Partnership's natural gas.

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 crude oil under the terms of these agreements, the dedication of the Partnership's future production is as follows:

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

• Piceance Basin contractual natural gas processing and firm sales dedications extend through 2022 and the contract provides the seller with the right to convert to a gathering and gas processing contract, solely.

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

Delivery to Market

The Partnership relies on PDC owned or third-party gathering and transmission pipelines to transport natural gas and NGLs production volumes to customers. In general, the Partnership has been, and expects to continue to be able to, produce and sell natural gas and NGLs 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's crude oil production is stored in tanks at or near the location of the Partnership's wells for routine pickup by crude oil transport trucks for direct delivery to regional refineries or crude oil pipeline interconnects for redelivery to those refineries. The cost of trucking or transporting the crude oil to market affects the price the Partnership ultimately receives for the crude oil.

Commodity Price Risk Management Activities

The Managing General Partner, on behalf of the Partnership in accordance with the D&O Agreement, utilizes commodity based derivative instruments to manage a portion of the Partnership's exposure to price volatility with regard to the Partnership's natural gas and crude oil sales. The financial instruments generally consist of collars, swaps and basis swaps and are NYMEX-traded and Colorado Interstate Gas, or CIG, based contracts. The Managing General Partner may utilize derivatives based on other indices or markets where appropriate. The contracts economically provide price stability for committed and anticipated natural gas and crude oil sales, generally forecasted to occur within the next two to four-year period. The Partnership's policies prohibit the use of commodity derivatives for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. The Managing General Partner manages price risk on only a portion of the Partnership's anticipated production, so the remaining portion of the Partnership's production is subject to the full fluctuation of market pricing.

The Managing General Partner uses financial derivatives to establish "floors" and "ceilings" or "collars" on the possible range of the prices realized for the sale of natural gas and crude oil in addition to fixing prices by using swaps. These derivatives are carried on the balance sheets at fair value with changes in fair values recognized currently in the statement of operations.

The Partnership is subject to price fluctuations for natural gas and crude oil sold in the spot market and under market index contracts. Currently, the Managing General Partner does not anticipate entering into additional commodity based derivative instruments on behalf of the Partnership. In addition, the Managing General Partner may close out any portion of derivatives that may exist from time to time which may result in a realized gain or loss on that derivative transaction.

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Governmental Regulation

While the prices of natural gas, NGLs and crude oil are market driven, other aspects of the Partnership's business and the industry in general are heavily regulated. The availability of a ready market for natural gas, NGLs and crude oil production depends on several factors beyond the Partnership's control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas, NGLs and crude oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. In general, state and federal regulations are intended to protect consumers from unfair treatment and oppressive control, to reduce environmental and health risks from the development and transportation of natural gas and crude oil, to prevent misuse of natural gas, NGLs and crude oil, to protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state and local agencies. In the western part of the U.S., governments own a large percentage of the land and control right to develop natural gas and crude oil. Government leases may subject to additional regulations and controls not common on private leases. The Managing General Partner takes the steps necessary to comply with applicable regulations, both on its own behalf and as part of the services provided to sponsored drilling partnerships. The Managing General Partner believes that it is in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following summary discussion of the regulation of the U.S. oil and gas 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.

Regulation of Natural Gas, NGLs and Crude Oil Production. The Partnership's production business is subject to various federal, state and local laws and regulations on the taxation of natural gas, NGLs and crude oil, the development, production and marketing of natural gas, NGLs and crude oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing refracing or recompletion activities for a well, the Managing General Partner must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies where the well drilled is located. Additionally, other regulated matters include:

• bond requirements in order to drill or operate wells;

• well locations;

• drilling and casing methods;

• surface use and restoration of well properties;

• well plugging and abandoning; and

• fluid disposal.

In addition, the Partnership's drilling activities involve hydraulic fracturing, which may be subject to additional federal and state disclosure and regulatory requirements discussed below in Environmental Matters. As a result, the Managing General Partner is unable to predict the future cost or effect of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas. Historically, the price of natural gas was subject to limitation by federal legislation. As of January 1, 1993, the Natural Gas Wellhead Decontrol Act removed all remaining federal price controls from natural gas sold in "first sales" on or after that date. The Federal Energy Regulatory Commission's, or FERC, jurisdiction over natural gas transportation was unaffected by the Decontrol Act.

The Managing General Partner moves natural gas and NGLs through pipelines owned by other companies, and sells natural gas and NGLs to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates.

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Each interstate natural gas pipeline company establishes its rates primarily through the FERC's rate-making process. Key determinants in the ratemaking process are:

• costs of providing service, including depreciation expense;

• allowed rate of return, including the equity component of the capital structure and related income taxes; and

• volume throughput assumptions.

The availability, terms and cost of transportation affect the Partnership's natural gas and NGLs sales. In the past, FERC has undertaken various initiatives to increase competition within the industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system was substantially restructured to remove various barriers and practices that historically limited non‑pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is greater access to transportation on interstate pipelines. In some cases, producers and marketers have benefited from this availability. However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently the Managing General Partner has seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in-gas, which could adversely affect cash flows from the affected area.

Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. The industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. The Managing General Partner cannot determine to what extent the Partnership's future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels.

Environmental Matters

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 restrictive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken that restricts drilling or imposing environmental protection requirements resulting in increased costs, the Partnership's business and prospects may be adversely affected.

The Partnership generates waste 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 adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by the Partnership's operations that are currently exempt from treatment as "hazardous wastes" may, in the future, be designated as "hazardous wastes," and therefore may subject the Partnership to more rigorous and costly operating and disposal requirements.

Hydraulic fracturing is commonly used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations such as shales that generally exist between 4,000 and 14,000 feet below ground. The Partnership routinely applies fracturing in its additional development activities. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over certain fracturing activities involving diesel under the federal Safe Drinking Water Act ("SDWA"), and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process.

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Colorado has adopted regulations that could impose more stringent permitting, transparency and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In December 2011, Colorado adopted a fracturing chemical disclosure rule wherein all chemicals used in the hydraulic fracturing of a well must be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission.

The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. The U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. These ongoing studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism.

In Colorado, local governing bodies have begun to issue drilling moratoriums or develop jurisdictional siting, permitting, and operating requirements. If new laws or regulations that significantly restrict hydraulic fracturing, or well locations, are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude the Partnership's ability to executing the Additional Development Plan. If hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, the Partnership's fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that the Partnership is ultimately able to produce from its reserves.

The Partnership currently owns properties that for many years have been used for the exploration and production of natural gas, NGLs and crude oil. Although the Partnership believes that the Partnership has utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques, and hydrocarbons or other wastes may have been disposed of or released on or under the properties that the Partnership owns or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, RCRA and analogous state laws, as well as state laws governing the management of natural gas and crude oil wastes. Under such laws, the Partnership may be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or remediate property contamination (including surface and groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. As an owner and operator of natural gas and crude oil wells, the Partnership may be liable pursuant to CERCLA and similar state laws.

The Partnership's operations are subject to the federal Clean Air Act, or CAA, and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the Partnership's operations. The EPA and states have been developing regulations to implement these requirements. The Partnership will be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. The New Source Performance Standards introduced by the EPA in 2011 will become effective in 2012, adding administrative and operational expense.

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The federal Clean Water Act, or CWA, and analogous state laws impose strict controls against the discharge of pollutants, including spills and leaks of crude oil and other substances. The CWA also regulates storm water run-off from natural gas and crude oil facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls and piping controls to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture, or leak.

Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including the Partnership, to procure and implement SPCC plans relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990, or OPA, subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, the Partnership has not experienced any significant crude oil discharge or crude oil spill problems.

In late 2011, the State of Colorado's Oil and Gas Conservation Commission ("Commission") adopted rules that require service companies and vendors to disclose all known chemicals in hydraulic fracturing fluid to operators and require operators to disclose such chemicals to the public through a website or, with respect to an operator's trade secrets, directly to the Commission or health professionals. The new rules also require operators seeking new location approvals to provide certain disclosures regarding fracturing to surface owners and adjacent property owners within 500 feet of a new well. These regulations will continue to increase the Partnership's costs.

The Partnership's expenses relating to preserving the environment have risen over the past few years and are expected to continue to rise in 2012 and beyond. Environmental regulations have had no materially adverse effect on the Partnership's ability to operate to date, but 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 the Partnership's business, financial condition or results of operations.

Industry Regulation

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

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 the FERC and Congress will continue. The Partnership cannot determine to what extent its future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. Illustrative of this trend are the regulations implemented in 2009 by the State of Colorado, which focus on the natural gas and crude oil industry. These multi-faceted regulations significantly enhance requirements regarding natural gas and crude oil permitting, environmental requirements and wildlife protection. Permitting delays and increased costs could result from these final regulations. Other potential or recently enacted laws and regulations affecting the Partnership include the following:

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

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

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• 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 additional development.

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

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

ii. If, as a result of the Dodd-Frank Act or its implementing regulations, the Managing General Partner is required to post cash collateral in connection with the Partnership's derivative positions, this would likely make it impracticable to implement the Partnership's current hedging strategy.

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

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

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

Competitive Market Position

Competition is high among persons and companies involved in the exploration and production of natural gas and crude oil. Because there are thousands of natural gas and crude oil companies in the United States, the national supply of natural gas, including the Rockies Region, is diversified. The Partnership believes that the drilling and production capabilities and the experience of the Managing General Partner's management and professional staff generally enable the Partnership to compete effectively. During 2010, the Managing General Partner has seen service costs steadily rise as crude oil prices and low cost shale opportunities have led to rig and completion crew redeployment. This trend continued throughout 2011. For more information on natural gas and crude oil pricing during 2011 and 2010, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations−Natural Gas and Crude Oil Sales. The Partnership believes that it can compete effectively in its area of operations. Nevertheless, the Partnership's results of operations and cash available for distributions could be materially adversely affected by the uncertainty in ascertaining the ultimate depth and duration of the current economic environment.

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

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

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

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

Reliance on Managing General Partner

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

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

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

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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.

Operating Hazards and Insurance. The Partnership's production operations include a variety of operating risks, including but not limited to fire, explosions, blowouts, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of natural gas. The occurrence of any of these could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean‑up responsibilities, regulatory investigation and penalties and suspension of operations. The Partnership's gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

Any significant problems related to the Partnership's facilities could adversely affect the Partnership's ability to conduct operations. In accordance with customary industry practice, PDC, in its capacity as Managing General Partner and operator, maintains insurance for the Partnership against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect the Partnership's operations and financial condition. The Partnership cannot predict whether insurance will continue to be available at premium levels that justify purchase or whether insurance will be available at all. 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.

PDC, in its capacity as Managing General Partner and operator, has purchased various insurance policies and lists the Partnership as a named insured on the 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, refracturing 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.

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Customers. PDC markets the natural gas, NGLs and crude oil from Partnership wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of the Partnership. Currently, PDC sells Partnership natural gas in the Piceance Basin to Williams, which has an extensive gathering and transportation system in this Basin. In the Wattenberg Field, the natural gas and NGLs are sold primarily to DCP, which gathers and processes the gas and liquefiable hydrocarbons produced. Natural gas and NGLs 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 and NGLs from the Partnership's wells to DCP and Williams are made on the spot market via open-access transportation arrangements through Williams or other pipelines and may be impacted by capacity interruptions on pipelines transporting natural gas out of the region.

The Partnership's crude oil production is sold, at or near the Partnership's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry, primarily as feedstock for refineries currently owned by Suncor, which are located north of Denver, Colorado. Oil prices fluctuate not only with the general market for oil as may be indicated by changes in the New York Mercantile Exchange, or NYMEX, but also due to changes in light-heavy crude oil supply and product demand-mix applicable to specific refining regions.

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

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, Business of this report 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 7, Commitments and Contingencies to the accompanying financial statements for additional information related to litigation.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5.MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS     

AND ISSUER PURCHASES OF EQUITY SECURITIES

At December 31, 2011, the Partnership had 1,793 Investor Partners holding 4,470 units and one Managing General Partner. The investments held by the Investor Partners are in the form of limited partnership interests. Investor Partners' interests are transferable; however, no assignee of units in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. As of December 31, 2011, the Managing General Partner has repurchased 5.5 units of Partnership interests from Investor Partners.

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

Cash Distribution Policy. PDC plans to make distributions of Partnership cash on a monthly basis, but no less often than quarterly, subject to funds being available for distribution. PDC will make cash distributions of 63% of cash available for distributions to the Investor Partners, including any Investor Partner units purchased by the Managing General Partner, and 37% of cash available for distributions to the Managing General Partner, throughout the term of the Partnership. Cash is distributed to the Investor Partners and PDC currently as a return of capital in the same proportion as their proportional interest in the net income of the Partnership. The Managing General Partner considers cash available for distributions to be the Partnership's net cash flows provided by operating activities less any net cash used in capital activities.

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

The ability of the Partnership to make or sustain cash distributions depends upon numerous factors. PDC can give no assurance that any level of cash distributions to the Investor Partners of the Partnership will be attained, that cash distributions will equal or approximate cash distributions made to investor partners of prior drilling programs sponsored by PDC, or that any level of cash distributions can be maintained. Fully developing all of the Partnership's properties would require substantial capital expenditures. Because of the restrictions set forth in the Agreement on making assessments on limited partnership units, the Partnership would generally be unable to fund such capital expenditures without bank borrowing or retaining all or a substantial portion of the Partnership's cash flow. At this time, the Managing General Partner does not anticipate electing to fund the initial or subsequent Codell formation refracturings or recompletions through bank borrowing.

Implementation of the Additional Development Plan would reduce or eliminate Partnership cash distributions to investors while the work is being conducted and paid for. All funds withheld for the Additional Development Plan reduce the cash distributions to both the Managing General Partner and Investor Partners in the same proportion as their proportional interest in the net income of the Partnership. These funds are held in the Partnership's bank account which is included in the Partnership's financial statements in “Cash and cash equivalents.” The intended use of this cash is for executing the Additional Development Plan; however, if an unexpected operational need would arise, the funds retained may be used to fulfill this obligation. The funds will be transferred to the Managing General Partner at the time these costs have been incurred. If the Managing General Partner would determine to abandon or delay a significant portion of the Additional Development Plan, any funds which were withheld and not used for these Partnership activities would be distributed to the Managing General Partner and Investor Partners based on their proportional

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share. Depending upon the level of withholding and the results of operations, it is possible that investors could have taxable income from the Partnership without any corresponding distributions in future years. If PDC were to be successful in the future acquisition effort of this Partnership, liquidation of the Partnership and a final payout would result in cessation of all future cash payments. The exchange by an investor partner of limited partnership units for cash pursuant to any merger would be a taxable transaction for U.S. federal income tax purposes. The effects of a potential acquisition may be different for each investor partner. For more information concerning the Partnership's Additional Development Plan see Item 1, Business - Operations, Drilling and Other Development Activities - Additional Development Plan. For additional information regarding PDC's disclosed partnership acquisition intentions, refer to the section entitled Recent Developments−PDC Sponsored Drilling Program Acquisition Plan on page 3 and Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations−PDC Sponsored Drilling Program Acquisition Plan.

Non-affiliated investor partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Additional Development Plan and any potential merger. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated investor partners should depend upon the advice of their own tax advisors concerning the effects of the Additional Development Plan and any potential merger.

The following table presents cash distributions made to the General Partner and Investor Partners for the periods indicated.

	Cash
Period	Distributions
For the year ended December 31, 2011	$	5,410,042
For the year ended December 31, 2010	14,355,892
For the period from the Partnership's inception to December 31, 2011	$	82,375,050

The volume and rate of production from producing wells naturally declines with the passage of time and is generally not subject to the control of management. The cash flow generated by the Partnership's activities and the amounts available for distribution to the Partnership's Investor Partners will, therefore, decline in the absence of significant increases in the prices that the Partnership receives for its natural gas, NGLs and crude oil production, or significant increases in the production of natural gas, NGLs and crude oil from the successful additional development of these properties, if any. The funds necessary for any additional development would be withheld from the Partnership's cash available for distributions. As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners would then decrease. For more information regarding the additional development of the Partnership's Wattenberg Field wells see Item 1, Business−Operations, Drilling and Other Development Activities -Additional Development Plan on page 6. 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−Financial Condition, Liquidity and Capital Resources.

The Agreement permits the Partnership to borrow funds on its behalf 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. At this time, the Managing General Partner does not anticipate electing to fund any of the Additional Development Plan activities through bank borrowings. (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.

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Unit Repurchase Program. Investor Partners may request that the Managing General Partner repurchase limited partnership units at any time beginning with the third anniversary of the first cash distribution of the Partnership. The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10% of the initial subscriptions if requested by an individual investor partner, subject to PDC's financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the Partnership to be treated as a “publicly traded partnership” or result in the termination of the Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis. In addition to the above repurchase program, individual investor partners periodically offer and PDC repurchases units on a negotiated basis before the third anniversary of the date of the first cash distribution. There were no negotiated-basis limited partnership units repurchased by PDC.

The following table presents information about the Managing General Partner's limited partner unit repurchases under the unit repurchase program during the periods indicated.

		Average Price
	Total Number of	Paid per
Period	Units Repurchased	Unit
October 1−31, 2011	—	$	—
November 1−30, 2011	3.50	4,437
December 1−31, 2011	—	—
Total fourth quarter Unit Repurchase Program repurchases	3.50

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 in this report.

Partnership Overview

Rockies Region 2007 Limited Partnership engages in the development, production and sale of natural gas, NGLs and crude oil. The Partnership began natural gas and crude oil operations in August 2007 and as of December 31, 2011, operates 99 gross (97.9 net) productive wells located in the Rocky Mountain Region in the state of Colorado. The Partnership drilled one additional well (1.0 net) which was declared to be a developmental dry hole due to down-hole mechanical failure that was subsequently plugged and abandoned. The Managing General Partner markets the Partnership's natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities or petroleum refiners or marketers, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces. PDC does not charge a separate fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or 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 tend to be affected by demand factors with a seasonal component.

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Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, which began in the fall of 2010 and extends through 2013, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of the particular partnership other than those held by PDC or its affiliates (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership. For additional information regarding PDC's intention to pursue acquisitions of PDC sponsored partnerships, refer to prior disclosure included in PDC's filings made with the SEC and presentations on PDC's website. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnership units held by the non-affiliated investor partners of such limited partnership. Consummation of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and each non-affiliated investor partner will receive the right to receive a cash payment for their limited partnership units in that partnership and will no longer participate in that partnership's future earnings or the Partnership's economic benefit.

During 2010 and 2011, PDC purchased twelve partnerships for the aggregate amount of $107.7 million. The feasibility and timing of any future cash purchase offer by PDC to any additional partnership, including this Partnership, depends on that partnership's suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership's well inventory; favorability of economics for the Wattenberg Field additional development, including commodity prices; and SEC reporting compliance status and timing and ability to achieve all necessary SEC approvals required to commence a merger and repurchase offer. On December 21, 2011, PDC and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to 11 partnership repurchases completed by mergers in 2010 and 2011.  The action was filed in U.S. District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp., et al.  PDC was managing general partner for each of these partnerships and the mergers were each approved by a majority of the non-PDC partnership units. The complaint includes allegations that the proxy statements issued in connection with the mergers were inadequate, and a breach of fiduciary duty.  On February 10, 2012, PDC filed a motion to dismiss or in the alternative, stay the action.  PDC believes the suit is without merit and intends to defend vigorously. There is no assurance that any potential proposed repurchase offer to any other of PDC's various public limited partnerships, including this Partnership, will occur.

Additional Development Plan

The Managing General Partner has prepared a plan for the Partnership's Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “Additional Development Plan”). The Additional Development Plan consists of the Partnership's refracturing of wells currently producing in the Codell formation and/or recompletion in the Niobrara or Codell formation which is currently not producing. Under the Additional Development Plan, the Partnership plans to initiate additional development activities during 2012. Refracturing activities consist of a second hydraulic fracturing treatment in a current production zone, while recompletion activities consist of an initial hydraulic fracturing treatment in a new production zone, all within an existing well bore.

Additional development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ten years after initial well drilling so that well resources are optimally utilized. This additional development would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to refracture or recomplete the individual wells and to determine the timing of any additional development activity. The timing of the refracturing or recompletion can be affected by the desire to optimize the economic return by additional development of the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership. On average, the production resulting from PDC's refracturings or recompletions have increased production; however, all refracturings or recompletions have not been economically successful and similar future refracturing or recompletion activities may not be economically successful. If the additional development work is performed, the Partnership will bear the direct costs of refracturing or recompletion, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from cash available for distributions. The Managing General Partner considers the cash available for distributions to be the Partnership's net cash flows provided by operating activities less any net cash used in capital activities.

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The Limited Partnership Agreement (the “Agreement”) permits the Partnership to borrow funds or receive advances, from the Managing General Partner, its affiliates or unaffiliated persons, for Partnership activities. At this time, the Managing General Partner does not anticipate electing to fund the initial Additional Development Plan's well refracturings or recompletions, nor any subsequent refracturings or recompletions, through bank borrowing. In the event that the Partnership's refracturing or recompletion activities are funded in part through borrowing, potential cash available for distributions derived from production increases provided by this additional development of the Partnership's Wattenberg Field wells may not be sufficient to repay the Partnership's borrowing financial obligations, which will include principal and interest. Borrowings, if any, will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for loan repayment. However, any bank borrowings may be collateralized by the Partnership's assets and may restrict distributions as long as there is a balance due on any loan.

During the fourth quarter of 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing or recompletion costs. This program will materially reduce, up to 100%, cash available for distributions of the partnerships for a period of time not to exceed five years.

Current estimated costs for these well refracturings or recompletions are between $180,000 and $260,000 per activity. As of December 31, 2011, this Partnership had scheduled to complete 87 additional development opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $19.3 million and $21.8 million if all of the activities are performed. The Managing General Partner will continually evaluate the timing of commencing these additional development activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development. During the three months ended December 31, 2011, $650,000 was withheld from the Partnership's cash distributions pursuant to the Additional Development Plan. Cumulatively, $2,620,000 has been withheld from Partnership distributions through February 29, 2012, and resides in the Partnership's bank account.

Both the number and timing of the additional development activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing and recompletion costs and projected cash withholding, all scheduled Partnership additional development activity will be completed within a five year period. Any funds not used for refracturing, recompletion or other operational needs will be distributed to the Managing General Partner and Investor Partners based on their proportional ownership interest.

Implementation of the Additional Development Plan has and will continue to reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership's funds. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliatedinvestor partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Additional Development Plan. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated investor partners should depend upon the advice of their own tax advisors concerning the effects of the Additional Development Plan.

Potential for Future Asset Impairments. The domestic natural gas market remains weak. A decrease in forward natural gas prices during 2012 could result in significant impairment charges. The Partnership's Piceance Basin has significant natural gas reserves, representing 69% of the total proved natural gas reserves and 47% of total proved reserves, and is sensitive to declines in natural gas prices. These assets, which had a net book value of approximately $17.5 million at December 31, 2011, are at risk of impairment if future natural gas prices for the Partnership's Piceance production experience further long-term decline. The cash flow model the Partnership uses to assess properties for impairment includes numerous assumptions, such as the Managing General Partner's estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices, operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward natural gas prices alone could result in a significant impairment of the Partnership's properties that are sensitive to declines in natural gas prices.

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2011 and 2010 Partnership Overview

Natural gas, NGLs and crude oil sales decreased by $3.9 million for the 2011 annual period compared to 2010, primarily due to a production volume decrease of 25%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $4.87 during 2011 compared to $4.99 for 2010. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased to $5.34 during 2011 from $6.18 during 2010. This decrease was primarily due to net realized derivative gains from natural gas and crude oil sales contributing only $0.47 per Mcfe, or $1 million, to the 2011 total revenues as compared to a $1.19 contribution per Mcfe, or $3.5 million, to 2010 total revenues. The Partnership's revenues were favorably impacted by unrealized derivative gains on natural gas and crude oil sales by $3.1 million and $4.7 million in 2011 and 2010, respectively.

The Partnership recorded an impairment loss of $27.7 million for the year ended December 31, 2010. The impairment loss resulted from the downward revision to the future net cash flows of production activities in the Piceance Basin in Colorado. See Note 10, Impairment of Capitalized Costs to the accompanying financial statements for additional disclosure related to the Partnership's proved property impairment.

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Results of Operations

Summary Operating Results

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

	Year ended December 31,
	2011			2010		Change
Number of producing wells (end of period)	99			99		—
Production(1)
Natural gas (Mcf)	1,704,713			2,243,886		(24	)%
NGLs (Bbl)	21,356			29,497		(28	)%
Crude oil (Bbl)	55,600			80,530		(31	)%
Natural gas equivalents (Mcfe)(2)	2,166,449			2,904,048		(25	)%
Average Mcfe per day	5,935			7,956		(25	)%
Natural Gas, NGLs and Crude Oil Sales
Natural gas	$	5,079,394		$	7,842,626	(35	)%
NGLs	587,985			785,262		(25	)%
Crude oil	4,892,815			5,861,127		(17	)%
Total natural gas, NGLs and crude oil sales	$	10,560,194		$	14,489,015	(27	)%
Realized Gain (Loss) on Derivatives, net
Natural gas	$	1,688,795		$	2,211,186	(24	)%
Crude oil	(683,764		)	1,258,230		(154	)%
Total realized gain on derivatives, net	$	1,005,031		$	3,469,416	(71	)%
Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	2.98		$	3.50	(15	)%
NGLs (per Bbl)	27.53			26.62		3	%
Crude oil (per Bbl)	88.00			72.78		21	%
Natural gas equivalents (per Mcfe)	4.87			4.99		(2	)%
Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	3.97		$	4.48	(11	)%
NGLs (per Bbl)	27.53			26.62		3	%
Crude oil (per Bbl)	75.70			88.41		(14	)%
Natural gas equivalents (per Mcfe)	5.34			6.18		(14	)%
Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)	$	2.02		$	1.74	16	%
Depreciation, depletion and amortization	2.47			3.26		(24	)%
Operating costs and expenses:
Direct costs - general and administrative	$	213,327		$	200,907	6	%
Depreciation, depletion and amortization	5,359,996			9,456,143		(43	)%
Loss on impairment of natural gas and crude oil properties	—			27,687,418		*
Cash distributions	$	5,410,042		$	14,355,892	(62	)%

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

Amounts may not recalculate due to rounding.

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_______________

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

⁽²⁾ Six Mcf of natural gas equals one Bbl of crude oil or NGL.

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

Natural Gas, NGLs and Crude Oil Sales

Changes in Natural Gas, NGLs and Crude Oil Sales Volumes. For the 2011 annual period compared to the 2010 annual period, natural gas, NGLs and crude oil production, on an energy equivalency-basis, decreased 25% due to normal production declines for this stage in the wells' production life cycle.

Changes in Natural Gas Sales. The $2.7 million, or 35%, decrease in natural gas sales for the 2011 annual period as compared to the 2010 annual period, was a reflection of the production volume decrease of 24% and by a lower average sales price per Mcf of 15%. The average sales price per Mcf, excluding the impact of realized derivative gains, was $2.98 for the current year annual period compared to $3.50 for the same period a year ago.

Changes in NGL Sales. The $0.2 million, or 25%, decrease in NGL sales for the 2011 annual period as compared to the 2010 annual period, was primarily a reflection of the production volume decrease of 28%, which was partially offset by a higher average sales price per Bbl of 3%. The average sales price per Bbl, excluding the impact of realized derivative gains, was $27.53 for the current year annual period compared to $26.62 for the same period a year ago.

Changes in Crude Oil Sales. The $1.0 million, or 17%, decrease in crude oil sales for the 2011 annual period as compared to the 2010 annual period, was primarily a reflection of the production volume decrease of 31%, which was partially offset by a higher average sales price per Bbl of 21%. The average sales price per Bbl, excluding the impact of realized derivative gains, was $88.00 for the current year annual period compared to $72.78 for the same period a year ago.

Natural Gas, NGLs and Crude Oil Pricing. The Partnership's results of operations depend upon many factors, particularly the price of natural gas, NGLs and crude oil and on PDC's ability to market the Partnership's production effectively. Natural gas, NGLs and crude oil prices are among the most volatile of all commodity prices. These price variations have a material impact on the Partnership's financial results and capital expenditures. Natural gas and NGLs prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. The combination of increased drilling activity and the lack of local markets has resulted in local market oversupply situations from time to time. Like most producers, the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond the Partnership's control. Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a market basket of prices, which generally includes natural gas sold at, near or below CIG prices in addition to other nearby region prices. The CIG Index and other indices for production delivered to other Rocky Mountain pipelines have historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential between NYMEX and CIG averaged $0.25 and $0.47 for 2011 and 2010, respectively.

Commodity Price Risk Management, Net

The Partnership uses various derivative instruments to manage fluctuations in natural gas prices. The Partnership has in place a variety of collars, fixed-price swaps and basis swaps on a portion of the Partnership's estimated natural gas production. The Partnership sells its natural gas at similar prices to the indices inherent in the Partnership's derivative instruments. As a result, for the volumes underlying the Partnership's derivative positions, the Partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the Partnership's commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps.

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Commodity price risk management, net, includes realized gains and losses and unrealized mark-to-market changes in the fair value of the derivative instruments related to the Partnership's natural gas and crude oil production. See Note 3, Fair Value Measurements and Disclosures and Note 4, Derivative Financial Instruments, to the Partnership's financial statements included in this report for additional details of the Partnership's derivative financial instruments.

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

	Year Ended December 31,
	2011			2010
Commodity price risk management gain, net:
Realized gains (losses)
Natural gas	$	1,688,795		$	2,211,186
Crude oil	(683,764		)	1,258,230
Total realized gains, net	1,005,031			3,469,416
Unrealized gains (losses)
Reclassification of realized gains included in
prior periods unrealized	(597,469		)	(519,880		)
Unrealized gains for the period	3,657,184			5,200,995
Total unrealized gains, net	3,059,715			4,681,115
Total commodity price risk management gain, net	$	4,064,746		$	8,150,531

Realized gains recognized in 2011 are primarily the result of lower natural gas prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas, exclusive of basis swaps, were $4.0 million, reflective of a higher weighted average strike price compared to the weighted average settlement price. These gains were offset in part by realized losses of $2.3 million on the Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted average price was narrower than the strike price of the Partnership's basis swaps. The net realized gains on natural gas derivative positions in 2011 were offset in part by realized losses of $0.7 million on the Partnership's crude oil positions as a result of higher prices at settlement compared to the respective strike price of the Partnership's derivative positions. Unrealized gains in 2011 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of the Partnership's open positions, offset in part by the narrowing of the CIG basis forward curve. During 2011, unrealized gains on the Partnership's natural gas positions were $4.3 million, offset in part by unrealized losses on the Partnership's CIG basis swaps of $0.6 million.

Realized gains recognized in 2010 were a result of lower natural gas and crude oil prices at settlement compared to the respective strike price, offset in part by the negative basis differential between NYMEX and CIG being narrower than the strike price of the Partnership's derivative position. During 2010, the Partnership recorded unrealized gains of $5.9 million on the Partnership's natural gas and crude oil positions that were partially offset by unrealized losses on its CIG basis swaps of $0.7 million as the forward basis differential between NYMEX and CIG had continued to narrow from the prior year.

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The following table presents the Partnership's derivative positions in effect as of December 31, 2011. Currently, the Partnership does not have any derivative positions for any of the Partnership's anticipated crude oil or NGL production.

	Collars					Fixed-Price Swaps			CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-MMBtu(1))	Weighted Average Contract Price				Quantity (Gas-MMBtu(1))	Weighted Average Contract Price		Quantity (Gas-MMBtu(1))	Weighted Average Contract Price			Fair Value at December 31, 2011(2)
		Floors		Ceilings
Natural Gas
NYMEX
01/01 - 03/31/2012	28,713	$	6.00	$	8.27	337,506	$	6.98	366,219	$	(1.88	)	$	788,355
04/01 - 06/30/2012	15,280	6.00		8.27		339,408	6.98		354,688	(1.88		)	773,678
07/01 - 09/30/2012	20,362	6.00		8.27		326,282	6.98		346,644	(1.88		)	702,765
10/01 - 12/31/2012	21,975	6.00		8.27		312,747	6.98		334,722	(1.88		)	585,359
01/01 - 03/31/2013	—	—		—		317,795	7.12		317,795	(1.88		)	508,818
04/01 - 06/30/2013	—	—		—		313,268	7.12		313,268	(1.88		)	527,708
07/01 - 09/30/2013	—	—		—		308,107	7.12		308,107	(1.88		)	492,370
10/01 - 12/31/2013	—	—		—		299,412	7.12		299,412	(1.88		)	410,282
Total Natural Gas	86,330					2,554,525			2,640,855				$	4,789,335

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

(2) As of December 31, 2011, approximately 3% of the fair value of the Partnership's derivative assets were measured using significant unobservable inputs (Level 3).

Natural Gas, NGLs and Crude Oil Production Costs

Natural gas, NGLs and crude oil production costs include production taxes and transportation costs which vary with revenues and production, well operating costs charged on a per well basis and other direct costs incurred in the production process. As production declines, fixed costs increase as a percentage of total costs resulting in production costs per unit increases. Typically, as production is expected to continue to decline, production costs per unit can be expected to increase in the future until such time as the Partnership successfully executes the Partnership's Additional Development Plan for the Wattenberg Field wells.

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

Changes in natural gas, NGLs and crude oil production expenses. Production and operating costs for 2011 decreased by approximately $700,000 compared to 2010. Lease operating costs were lower by approximately $610,000 in 2011 as workovers, tubing repairs and non-recurring environmental remediation activities collectively were higher in 2010. Revenue and volume-based costs were lower by approximately $150,000 in 2011 consistent with sales and production declines from 2010. Production and operating costs per Mcfe increased to $2.02 during 2011 from $1.74 in 2010 due to lower volumes partially offset by the decrease in costs.

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Depreciation, Depletion and Amortization

Natural gas and crude oil properties. Depreciation, depletion and amortization ("DD&A") expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. DD&A expense is primarily based upon year-end proved developed producing reserves. The pricing measurement for reserve estimations is a 12-month average of the first day of the month price for each month in the period. If prices increase, the estimated volumes of proved reserves will increase, resulting in decreases in the rate of DD&A per unit of production. If prices decrease, the estimated volumes of proved reserves will decrease, resulting in increases in the rate of DD&A per unit of production.

Changes in DD&A expense. The aggregate DD&A expense rate per Mcfe decreased to $2.47 for 2011 compared to $3.26 during 2010. The decrease in the per Mcfe rate is primarily the result of recording impairment expenses for the Partnership's Piceance Basin wells as of December 31, 2010. The impairment provision and lower production volumes resulted in a decrease in Depreciation, depletion and amortization expense of $4.1 million in 2011 compared to 2010.

Loss on Impairment of Natural Gas and Crude Oil Properties

The Partnership assesses its proved natural gas and crude 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 Managing General Partner reasonably estimates the commodities to be sold. The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to the Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership's proved natural gas and crude oil properties. If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, as occurred for the year ended December 31, 2010, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. The Partnership's estimated production used in the impairment testing is taken from the annual reserve report (See Supplemental Natural Gas, NGL and Crude Oil Information –Unaudited—Net Proved Reserves). Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. A decline in the forward price curves used to estimate future cash flows at December 31, 2010, accompanied by lower reserves reflected in the Partnership's annual reserve report resulted in an impairment in the fourth quarter of 2010. This downward revision to the future net cash flows resulted primarily from an 8,034 MMcf, or 33.5%, decrease in future estimated natural gas production due to well economics and a reduction in prices from 2009. The Partnership recorded an impairment loss, the first natural gas and oil properties impairment recognized by the Partnership since it began operations in 2007, of $27.7 million for the year ended December 31, 2010. The impairment loss resulted from the downward revision to the fair value of discounted future net cash flows of production activities in the Piceance Basin in Colorado. There was no impairment in 2011.

Financial Condition, Liquidity and Capital Resources

The Partnership's primary sources of cash for both the 2011 and 2010 annual periods, were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the net realized gains from the Partnership's derivative positions. These sources of cash were primarily used to fund the Partnership's operating costs, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner. During the year ended December 31, 2011, the Managing General Partner withheld $2,000,000 from the Partnership's cash distributions pursuant to the Additional Development Plan. Through February 29, 2012, $2,620,000 has been withheld from Partnership distributions to fund this plan. These and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing or recompletion costs to be incurred during 2012 and beyond. For additional information, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments-Additional Development Plan.

Fluctuations in the Partnership's operating cash flows are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership's cash flow from operations becomes the net activity between the Partnership's natural gas, NGLs and crude oil sales

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and realized natural gas and crude oil derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership's expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of December 31, 2011, the Partnership had natural gas derivative positions in place covering 97% of the expected natural gas production for the year ending December 31, 2012, at an average price of $5.04 per Mcf. However, the Partnership has no NGL or crude oil derivatives. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership's revenues.

The Partnership's future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity derivatives. Natural gas, NGLs and crude oil production from the Partnership's existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership's operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2012 and beyond, and may substantially reduce or restrict the Partnership's ability to participate in the additional development activities which are more fully described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Additional Development Plan.

Although the Agreement permits the Partnership to borrow funds on its behalf for Partnership activities, the Managing General Partner does not anticipate electing to fund through bank borrowings, any portion of the Partnership's refracturing and recompletion activities. These refracturings and recompletions are scheduled to begin in 2012. Partnership borrowings, should any occur, will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for repaying the loan.

Working Capital

The Partnership had working capital of $6.7 million at December 31, 2011, compared to working capital of $2.9 million at December 31, 2010, an increase of approximately $3.8 million. This increase was primarily due to the following:

• Cash and cash equivalents increased by $2 million between December 31, 2011 and December 31, 2010.

• Accounts receivable decreased by $0.5 million between December 31, 2011 and December 31, 2010.

• Realized and unrealized derivative gains receivable increased by $2.1 million between December 31, 2011 and December 31, 2010.

• Due to the Managing General Partner, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, decreased by $0.2 million between December 31, 2011 and December 31, 2010.

Working capital is expected to increase due to the Partnership’s anticipated withholding of cash from the Managing General Partner and Investor Partners, on a pro-rata basis, for the initial refracturing activities. This withholding, which began in the fourth quarter of 2010, totals $2,620,000 as of February 29, 2012. Cash will begin to decrease as the funds are utilized in payment of completed development activities, currently planned to occur during 2012. Funding for the Additional Development Plan will be provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners on a percentage of Partnership ownership pro-rata basis. Working capital is expected to similarly fluctuate by increasing during periods of Additional Development Plan funding and by decreasing during periods when payments are made for completed refracturing or recompletion.

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Cash Flows

Cash Flows from Operating Activities

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

The price the Partnership receives on its natural gas sales is impacted by the Managing General Partner's transportation, gathering and processing agreements. The Partnership currently uses the "net-back" method of accounting for these arrangements related to the Partnership's natural gas sales. The Partnership sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

Net cash provided by operating activities was $7.5 million for the year ended December 31, 2011, compared to $15.1 million for the comparable period in 2010. The decrease of $7.6 million in cash provided by operating activities was due primarily to the following:

• A decrease in natural gas, NGLs and crude oil sales receipts of $4.5 million, or 29%,

• A decrease in commodity price risk management realized gains receipts of $3.5 million, or 74%, and

• A decrease in production costs and direct costs - general and administrative payments of $0.4 million.

Cash Flows from Investing Activities

The Partnership, from time-to-time, invests in equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts totaled $0.1 million for each of the years ended December 31, 2011 and 2010.

Cash Flows from Financing Activities

The Partnership initiated monthly cash distributions to investors in May 2008 and has distributed $82.4 million through December 31, 2011. The table below presents cash distributions to the Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to PDC for the Managing General Partner's 37% general partner interest in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 63% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.

	Managing		Investor
	General Partner		Partners		Total
Year Ended	Distributions		Distributions		Distributions
2011	$	2,001,716	$	3,408,326	$	5,410,042
2010	$	5,311,680	$	9,044,212	$	14,355,892

The decrease in total distributions for 2011 as compared to 2010 is primarily due to the significant decrease in cash flows from operating activities during 2011 and from funds held by the Managing General Partner for the Additional Development Plan. The Partnership began funding for the Additional Development Plan during October 2010. During the year ended December 31, 2011, on a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $740,000 and $1,260,000 from the Managing General Partner and Investor Partners' share of cash available for distributions, respectively. For additional information, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Additional Development Plan.

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Off-Balance Sheet Arrangements

As of December 31, 2011, the Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on the Partnership's financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Commitments and Contingencies

See Note 7, Commitments and Contingencies, to the accompanying financial statements included in this Annual report.

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies to the accompanying financial statements included in this Annual Report.

Critical Accounting Policies and Estimates

The Managing General Partner has identified the following policies as critical to business operations and the understanding of the results of the operations of the Partnership. The following is not a comprehensive list of all of the Partnership's critical accounting policies and estimates. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States of America, 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:

Natural Gas and Crude Oil Properties

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

The Partnership assesses its natural gas and crude 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 management reasonably estimates commodities to be sold. Any impairment in value is charged to impairment of natural gas and crude oil properties. The estimates of future prices may differ from current market prices of natural

34

gas, NGLs and crude oil. Any downward revisions in estimates to the Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and therefore a reduction in undiscounted future net cash flows and an impairment of the Partnership's natural gas and crude oil properties. Although the Partnership's cash flow estimates 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. See Note 10, Impairment of Capitalized Costs to the accompanying financial statements for additional disclosure related to the Partnership's proved property impairment.

Natural Gas, NGLs and Crude Oil Sales Revenue Recognition

Natural gas, NGLs and crude oil sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. The Partnership records sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. The Managing General Partner estimates the Partnership's sales volumes based on the Managing General Partner's measured volume readings. The Managing General Partner then adjusts the Partnership's natural gas, NGL and crude oil sales in subsequent periods based on the data received from the Partnership's purchasers that reflects actual volumes and prices received. The Partnership receives payment for sales from one to three months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded up to two months later. Historically, differences have been immaterial.

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.

• Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means. Includes the Partnership's fixed-price swaps and basis swaps.

• Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Includes the Partnership's natural gas collars.

Derivative Financial Instruments. The Managing General Partner measures the fair value of the Partnership's derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validates its fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

35

The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership's derivative assets, which are primarily financial institutions who are also major lenders in the Managing General Partner's corporate credit facility agreement, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner's evaluation, the Managing General Partner has determined that the impact of the nonperformance of the Managing General Partner's counterparties on the fair value of the Partnership's derivative instruments is insignificant.

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The response to this Item is set forth herein in a separate section of this report, beginning at page F-1.

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

None.

ITEM 9A.CONTROLS AND PROCEDURES

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

(a) Evaluation of Disclosure Controls and Procedures

As of December 31, 2011, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that the Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, and that such information is accumulated and communicated to the Partnership's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.

Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and the Chief Financial Officer concluded that the Partnership's disclosure controls and procedures were effective as of December 31, 2011.

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

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

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

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

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

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

Management of the Managing General Partner has assessed the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2011, based upon the criteria established in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management of the Managing General Partner concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2011.

Exchange Act Rules 13a-15(c) and 15d - 15(c) and Section 404 of the Sarbanes-Oxley Act of 2002 require management of the Partnership to conduct an annual evaluation of the Partnership's internal control over financial reporting and to provide a report on management's assessment, including a statement as to whether or not internal control over financial reporting is effective. Since the Partnership is neither an accelerated filer nor a large accelerated filer as defined by SEC regulations, the Partnership's internal control over financial reporting was not subject to attestation by the Partnership's independent registered public accounting firm. As such, this Form 10-K does not contain an attestation report of the Partnership's independent registered public accountant regarding internal control over financial reporting.

(c) Changes in Internal Control over Financial Reporting

During the three months ended December 31, 2011, PDC, the Managing General Partner, made no changes in the Partnership's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect the Partnership's internal control over financial reporting.

ITEM 9B.OTHER INFORMATION

None.

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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 traded Nevada corporation, was organized in 1955. The common stock of PDC is traded on the NASDAQ Global Select Market under the symbol "PETD." The business and affairs of the Partnership are managed by the Managing General Partner through the D&O Agreement, by or under the direction of PDC's Board of Directors (the “Board”), in accordance with Nevada law and PDC's By-Laws. The directors' fiduciary duty is to exercise their business judgment in the best interests of PDC's shareholders, and in that regard, as Managing General Partner, the best interests of the Partnership and other sponsored drilling partnerships. The Board has adopted Corporate Governance Guidelines that govern the structure and functioning of the Board and establish the Board's policies on a number of corporate governance issues. In connection with the appointment of Mr. Trimble as Chief Executive Officer and President of PDC in June 2011, and as part of PDC's ongoing effort to engender sound corporate governance best practices, PDC separated the Chief Executive Officer and Chairman positions, and appointed Mr. Swoveland as the non-executive Chairman of the Board of Directors. Separating these positions allows PDC's Chief Executive Officer to focus on developing and implementing PDC's business plans and supervising PDC's day-to-day business operations, and allows the Chairman to lead the Board of Directors in its oversight and advisory roles. Due to the many responsibilities of the Board of Directors and the significant time and effort required by each of the Chairman and the Chief Executive Officer to perform their respective duties, PDC believes that having separate persons in these roles enhances the ability of each to discharge those duties effectively. The Board of Directors also believes that having separate positions provides a clear delineation of responsibilities for each position and fosters greater accountability of management. Given the transition in leadership, the Board of Directors determined for the foregoing reasons that separating these positions and implementing this leadership structure is appropriate and in the best interests of PDC's stockholders. PDC will continue to evaluate whether this leadership structure best serves PDC and its stockholders at the time of the Chairman's election, annually or as circumstances warrant.

The Managing General Partner's Board seeks to understand and oversee critical business risks. Risks are considered in every business decision, not just through Board oversight of the Managing General Partner's Risk Management system. The Board realizes, however, that it is not possible to eliminate all risk, nor is it desirable, and that appropriate risk-taking is essential to achieve the Managing General Partner's objectives. The Board's risk oversight structure provides that management report on critical business risk issues to the Planning and Finance Committee, which includes in part, an oversight function concerning PDC's liquidity, operational and credit risk management. In this regard, the Planning and Finance Committee also provides similar risk assessment and management process oversight functions for sponsored drilling program partnerships, which includes the Partnership. Other Board committees, however, are active in managing the risks related to such committee's oversight areas. For example, the Audit Committee reviews many risks and related controls in areas that it considers fundamental to the integrity and reliability of PDC's financial statements, such as counterparty risks and derivative program risks. The Managing General Partner's Board has established the Audit Committee, including a subcommittee which focuses specifically on financial reporting matters of PDC's sponsored drilling partnerships, to assist the Board in monitoring not only the integrity of the Managing General Partner's financial reporting systems and internal controls but also PDC's legal and regulatory compliance. The Board has created a Special Transaction 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. Jeffrey C. Swoveland chairs the Special Transaction Committee; other members are Directors Crisafio, Mazza and Parke. The Special Transaction Committee has not been asked to consider a repurchase of Rockies Region 2007 Limited Partnership at this time.

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Managing General Partner Duties and Resource Allocation

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

• Profitable development and cost-effective production operations of the Partnership's reserves;

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

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

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

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

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Petroleum Development Corporation (dba PDC Energy)

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

Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires
James M. Trimble	63	Chief Executive Officer, President and Director	2009	2013
Gysle R. Shellum	60	Chief Financial Officer	—	—
R. Scott Meyers	37	Chief Accounting Officer	—	—
Barton R. Brookman, Jr.	49	Senior Vice President Exploration and Production	—	—
Daniel W. Amidon	51	General Counsel and Secretary	—	—
Lance Lauck	49	Senior Vice President Business Development	—	—
Jeffrey C. Swoveland	57	Chairman and Director	1991	2014
Joseph E. Casabona	68	Director	2007	2014
Anthony J. Crisafio	59	Director	2006	2012
Larry F. Mazza	51	Director	2007	2013
David C. Parke	45	Director	2003	2014
Kimberly Luff Wakim	53	Director	2003	2012

James M. Trimblewas appointed as the Chief Executive Officer and President of PDC in June 2011. Mr. Trimble retired in November 2010 as Managing Director of Grand Gulf Energy, Limited (ASX: GGE), a public company traded on the Australian Securities Exchange, a position he had held since August 2005. He remains a member of the board of Directors of Grand Gulf Energy, Limited. In January 2005, Mr. Trimble founded and served until November 2010 as President and Chief Executive Officer of the U.S. subsidiary Grand Gulf Energy Company LLC, an exploration and development company focused primarily on drilling in mature basins in Texas, Louisiana and Oklahoma. From 2000 through 2004, Mr. Trimble was Chief Executive Officer of Elysium Energy and then Tex-Cal Energy LLC, both of which were privately held oil and gas companies that he was brought in to take through troubled workout solutions. Prior to this, he was Senior Vice President of Exploration and Production for Cabot Oil and Gas (NYSE: COG). Mr. Trimble was hired in July 2002 as CEO of TexCal (formerly Tri-Union Development) to manage a distressed oil and gas company through bankruptcy, and that company filed for Chapter 11 reorganization within 45 days after the date that Mr. Trimble accepted such employment. He successfully managed the company through its exit from bankruptcy in 2004. From November 2002 until May 2006, he also served as a director of Blue Dolphin Energy, an independent oil & gas company with operations in the Gulf of Mexico. Mr. Trimble serves as Chairman of the Executive Committee and serves on the Planning and Finance Committee.

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

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

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

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

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

Jeffrey C. Swoveland was appointed as the Chairman of the Board of Directors of PDC in June 2011. Mr. Swoveland is President and Chief Executive Officer of ReGear Life Sciences, Inc. in Pittsburgh, Pennsylvania (previously named Coventina Healthcare Enterprises), which develops and markets medical device products, where he was previously Chief Operating Officer. From 2000 until 2007, Mr. Swoveland served as Chief Financial Officer of Body Media, Inc., a life-science company specializing in the design and development of wearable body monitoring products and services. Prior thereto, Mr. Swoveland held various positions, including Vice-President of Finance, Treasurer and interim Chief Financial Officer with Equitable Resources, Inc., a diversified natural gas company, from 1994 to September 2000. Mr. Swoveland serves as a member of the Board of Directors of Linn Energy, LLC, a public, independent natural gas and oil company. Mr. Swoveland serves on the Audit Committee, the Planning and Finance Committee, the Compensation Committee and the Executive 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 until his retirement in May 2007. Mr. Casabona's responsibilities included strategic planning as well as executive oversight of drilling operations in the continental U.S. and internationally. From 2008 until the beginning of 2011, Mr. Casabona served as Chief Executive Officer of Paramax Resources Ltd, a junior public Canadian oil & gas company (PMXRF) engaged in the business of acquiring and exploration of oil and gas prospects, primarily in Canada and Idaho. Mr. Casabona serves as Chairman of the Planning and Finance Committee and serves on the Audit Committee.

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

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

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David C. Parke is a Managing Director in the investment banking group of Burrill & Company. From 2006 until June 2011, he was a Managing Director of Boenning & Scattergood, Inc., 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.

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

Audit Committee

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

ITEM 11.EXECUTIVE COMPENSATION

The Partnership does not have any employees or executives of its own. None of PDC's officers or directors receive any direct remuneration, compensation or reimbursement from the Partnership. These persons receive compensation solely from PDC. The Managing General Partner does not believe that PDC's executive and non-executive compensation structure, available to officers or directors who act on behalf of the Partnership, is reasonably likely to have a materially adverse effect on the Partnership's operations or conduct of PDC when carrying out duties and responsibilities to the Partnership, as Managing General Partner under the Agreement, or as operator under the D&O Agreement. The management fee and other amounts paid to the Managing General Partner by the Partnership are not used to directly compensate or reimburse PDC's officers or directors. No management fee was paid to PDC in 2011 or 2010 as the Partnership is not required to pay a management fee other than a one-time fee paid in the initial year of formation per the Agreement. The Partnership pays a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $100 per well per month for Partnership related general and administrative expenses that include accounting, engineering and management of the Partnership by the Managing General Partner. See Item 13, Certain Relationships and Related Transactions, and Director Independence for a discussion of compensation paid by the Partnership to the Managing General Partner.

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

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ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

RELATED STOCKHOLDER MATTERS

The following table presents information as of December 31, 2011, 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
	Number of	Number of Units Beneficially Owned	Percentage of Total Units Outstanding		Percentage of
	Units				Total Partnership
	Outstanding Which				Interests
	Represent 63% of Total				Beneficially
Person or Group	Partnership Interests (1)				Owned
	4,470.00
Petroleum Development Corporation (2) (3) (4) (5)	—	5.50	0.12	%	0.08	%
Investor Partners beneficially owning 5% or more, of limited partner interests	—	—	—		—

(1) Additional general partner units were converted to limited partner interests at the completion of drilling activities.

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

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

(4) The Percentage of “Total Partnership Interests Beneficially Owned” by PDC with respect to its limited partnership units repurchased is determined by multiplying the percentage of limited partnership units repurchased by PDC to total limited partnership units, by the limited partners' percentage ownership in the Partnership. [(5.5 units/4,470 units)*63% limited partnership ownership]

(5) In addition to this ownership percentage of limited partnership interest, Petroleum Development Corporation (dba PDC Energy) owns a Managing General Partner interest of 37%.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR

INDEPENDENCE

Compensation to the Managing General Partner and Affiliates

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

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

• 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 reserves at least annually and monitor individual well performance against expectations; and

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

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

PDC procures services on behalf of the Partnership for costs and expenses related to the purchase or repairs of equipment, materials, third-party services, brine disposal and the rebuilding of access roads. These are charged at the invoice cost of the materials purchased or the third-party services performed. In addition to the industry specialists above who provide technical management, PDC may provide services, at competitive rates, from PDC-owned service rigs, a water truck, steel tanks used temporarily on the well location during the drilling and completion of a well, roustabouts and other assorted small equipment and services. A roustabout is a natural gas and oil field employee who provides skilled general labor for assembling well components and other similar tasks. PDC may lay short gathering lines, or may subcontract all or part of the work where it is more cost effective for the Partnership.

See Note 9, Transactions with Managing General Partner and Affiliates to the accompanying financial statements, for information regarding compensation to and transactions with the Managing General Partner and affiliates.

Related Party Transaction Policies and Approval

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

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	2011		2010
Audit Fees (1)	$	160,000	$	140,000

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

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Audit Committee Pre-Approval Policies and Procedures

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

Part IV

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

(b)    Exhibits index.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
3.1	Limited Partnership Agreement	10-12G/A Amend 1	000-53201	3	08/06/2008
3.2	Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law	10-12G/A Amend 1	000-53201	3.1	08/06/2008
10.1	Form of assignment of leases to the Partnership	10-12G/A Amend 1	000-53201	10.1	08/06/2008
10.2	Drilling and operating agreement between PDC as Managing General Partner, and the Partnership	10-12G/A Amend 1	000-53201	10.2	08/06/2008
10.3	Audited Consolidated Financial Statements for the year ended December 31, 2011 of Petroleum Development Corporation (dba PDC Energy) and its subsidiaries, as Managing General Partner of the Partnership	10-K	000-07246		03/01/2012

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
10.4	Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.3	03/31/2009
10.5	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982-A Limited and Cattle Creek Company, dated October 14, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.4	03/31/2009
10.6	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and SHF Partnership, a Colorado general partnership, Trailblazer Oil and Gas, Inc., Alfa Resources, Inc., Pulsar Oil and Gas, Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert Lanari, an individual, and Toby A Martinez, an individual, dated September 21, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.5	03/31/2009
10.7	Domestic Crude Oil Purchase Agreement with ConocoPhillips Company, dated January 1, 1993, as amended by agreements with Teppco Crude Oil, LLC dated August 2, 2007; September 24, 2007; October 17, 2007; January 7, 2008; January 15, 2008; and April 17, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.6	03/31/2009

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
10.8	Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and Petroleum Development Corporation, dated as of June 1, 2006 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.7	03/31/2009
10.9	First Amendment to the Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas and Petroleum Development Corporation, dated as of June 1, 2011 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	8-K	000-07246	10.1	08/02/2011
10.10	Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and Petroleum Development Corporation, dated April 22, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-Q	000-53201	10.1	05/18/2009
10.11	Domestic Crude Oil Purchase Agreement between Shell Trading (US) Company and Petroleum Development Corporation, dated September 13, 2007	10-K	000-52787	10.9	03/31/2009
31.1	Certification by Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
31.2	Certification by Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
32.1**	Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Report of Independent Petroleum Consultants − Ryder Scott Company, LP					X
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document
** Furnished herewith.

48

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 2007 Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)

By: /s/ James M. Trimble

James M. Trimble

President and Chief Executive Officer

of Petroleum Development Corporation (dba PDC Energy)

March 27, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ James M. Trimble	President, Chief Executive Officer and Director	March 27, 2012
James M. Trimble	Petroleum Development Corporation (dba PDC Energy) Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	March 27, 2012
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy) Managing General Partner of the Registrant
	(Principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	March 27, 2012
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy) Managing General Partner of the Registrant
	(Principal accounting officer)
/s/ Jeffrey C. Swoveland	Chairman and Director	March 27, 2012
Jeffrey C. Swoveland	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
/s/ Joseph E. Casabona	Director	March 27, 2012
Joseph E. Casabona	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
/s/ Anthony J. Crisafio	Director	March 27, 2012
Anthony J. Crisafio	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
/s/ Kimberly Luff Wakim	Director	March 27, 2012
Kimberly Luff Wakim	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant

49

Rockies Region 2007 Limited Partnership

Index to Financial Statements

Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets - December 31, 2011 and 2010	F-3
Statements of Operations - For the Years Ended December 31, 2011 and 2010	F-4
Statements of Partners' Equity - For the Years Ended December 31, 2011 and 2010	F-5
Statements of Cash Flows - For the Years Ended December 31, 2011 and 2010	F-6
Notes to Financial Statements	F-7
Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited	F-20

F-1

Report of Independent Registered Public Accounting Firm

To the Partners of the Rockies Region 2007 Limited Partnership,

In our opinion, the accompanying balance sheets and the related statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of Rockies Region 2007 Limited Partnership (the "Partnership") at December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 9 to the financial statements, the Partnership has significant related party transactions with Petroleum Development Corporation and its subsidiaries.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

March 27, 2012

F-2

Rockies Region 2007 Limited Partnership

Balance Sheets

	As of December 31,
	2011			2010
Assets
Current assets:
Cash and cash equivalents	$	2,690,377		$	690,377
Accounts receivable	767,950			1,175,972
Crude oil inventory	47,247			59,031
Due from Managing General Partner-derivatives	5,067,966			3,178,313
Due from Managing General Partner-other, net	411,571			534,115
Total current assets	8,985,111			5,637,808
Natural gas and crude oil properties, successful efforts method, at cost	80,260,368			79,934,322
Less: Accumulated depreciation, depletion and amortization	(35,059,637		)	(29,699,641		)
Natural gas and crude oil properties, net	45,200,731			50,234,681
Due from Managing General Partner-derivatives	3,844,431			4,689,041
Total non-current assets	49,045,162			54,923,722
Total Assets	$	58,030,273		$	60,561,530
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	95,529		$	136,704
Due to Managing General Partner-derivatives	2,217,809			2,580,843
Total current liabilities	2,313,338			2,717,547
Due to Managing General Partner-derivatives	1,905,253			3,556,891
Asset retirement obligations	1,031,186			727,952
Total liabilities	5,249,777			7,002,390
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	14,334,835			14,622,934
Limited Partners - 4,470 units issued and outstanding	38,445,661			38,936,206
Total Partners' equity	52,780,496			53,559,140
Total Liabilities and Partners' Equity	$	58,030,273		$	60,561,530

See accompanying notes to financial statements.

F-3

Rockies Region 2007 Limited Partnership

Statements of Operations

	Year ended December 31,
	2011		2010
Revenues:
Natural gas, NGLs and crude oil sales	$	10,560,194	$	14,489,015
Commodity price risk management gain, net	4,064,746		8,150,531
Total revenues	14,624,940		22,639,546
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	4,368,553		5,061,490
Direct costs - general and administrative	213,327		200,907
Depreciation, depletion and amortization	5,359,996		9,456,143
Accretion of asset retirement obligations	52,555		47,304
Loss on impairment of natural gas and crude oil properties	—		27,687,418
Total operating costs and expenses	9,994,431		42,453,262
Income (loss) from operations	$	4,630,509	$	(19,813,716	)
Interest income	889		—
Net income (loss)	$	4,631,398	$	(19,813,716	)
Net income (loss) allocated to partners	$	4,631,398	$	(19,813,716	)
Less: Managing General Partner interest in net income (loss)	1,713,617		(7,331,075		)
Net income (loss) allocated to Investor Partners	$	2,917,781	$	(12,482,641	)
Net income (loss) per Investor Partner unit	$	653	$	(2,793	)
Investor Partner units outstanding	4,470.00		4,470.00

See accompanying notes to financial statements.

F-4

Rockies Region 2007 Limited Partnership

Statements of Partners' Equity

For the Years Ended December 31, 2011 and 2010

				Managing
	Investor			General
	Partners			Partner			Total
Balance, December 31, 2009	$	60,463,059		$	27,265,689		$	87,728,748
Distributions to partners	(9,044,212		)	(5,311,680		)	(14,355,892		)
Net loss	(12,482,641		)	(7,331,075		)	(19,813,716		)
Balance, December 31, 2010	38,936,206			14,622,934			53,559,140
Distributions to partners	(3,408,326		)	(2,001,716		)	(5,410,042		)
Net income	2,917,781			1,713,617			4,631,398
Balance, December 31, 2011	$	38,445,661		$	14,334,835		$	52,780,496

See accompanying notes to financial statements.

F-5

Rockies Region 2007 Limited Partnership

Statements of Cash Flows

	Year ended December 31,
	2011			2010
Cash flows from operating activities:
Net income (loss)	$	4,631,398		$	(19,813,716	)
Adjustments to net income (loss) to reconcile to net cash    provided by operating activities:
Depreciation, depletion and amortization	5,359,996			9,456,143
Accretion of asset retirement obligations	52,555			47,304
Unrealized gain on derivative transactions	(3,059,715		)	(4,681,115		)
Loss on impairment of natural gas and crude oil properties	—			27,687,418
Changes in operating assets and liabilities:
Decrease in accounts receivable	408,022			366,833
Decrease (increase) in crude oil inventory	11,784			(24,077		)
Decrease in accounts payable and accrued expenses	(41,175		)	(57,085		)
Decrease in Due from Managing General Partner - other, net	122,544			2,130,851
Net cash provided by operating activities	7,485,409			15,112,556
Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	(75,367		)	(70,516		)
Net cash used in investing activities	(75,367		)	(70,516		)
Cash flows from financing activities:
Distributions to Partners	(5,410,042		)	(14,355,892		)
Net cash used in financing activities	(5,410,042		)	(14,355,892		)
Net increase in cash and cash equivalents	2,000,000			686,148
Cash and cash equivalents, beginning of period	690,377			4,229
Cash and cash equivalents, end of period	$	2,690,377		$	690,377
Supplemental disclosure of non-cash activity:
Change in asset retirement obligation, with corresponding increase to natural gas and crude oil properties	$	250,679		$	—

See accompanying notes to financial statements.

F-6

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

NOTE 1 - GENERAL

Rockies Region 2007 Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and crude oil properties. Business operations 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”), which conducts business under the name PDC Energy, to conduct and manage the Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of December 31, 2011, there were 1,793 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 37% Managing General Partner ownership in the Partnership. According to the terms of the Limited Partnership Agreement, revenues, costs and cash distributions of the Partnership are allocated 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, 2011, the Managing General Partner has repurchased 5.5 units of Partnership interests from Investor Partners at an average price of $4,577 per unit. As of December 31, 2011, the Managing General Partner owns 37.08% of the Partnership.

The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner's limited partner unit repurchase program, see Note 8, Partners' Equity and Cash Distributions.

Certain reclassifications have been made to the prior period disclosures to conform to the current year presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership's previously reported financial position, cash flows, net income or partners' equity. See Note 3, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership's derivative instruments.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management's Estimates

The preparation of the Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires the Partnership to make estimates and assumptions that affect the amounts reported in the Partnership's financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas, natural gas liquids (“NGL” or “NGLs”) and crude oil sales revenue, proved reserves, future cash flows from natural gas and crude oil properties and valuation of derivative instruments.

Basis of Presentation

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

Cash and Cash Equivalents. The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. The balance in the Partnership's account is insured by Federal Deposit Insurance Corporation, or FDIC, up to $250,000 through December 31, 2013. The Partnership has not experienced losses in any such accounts to date and limits the Partnership's exposure to credit loss by placing its cash and cash equivalents with a high-quality financial institution.

Accounts Receivable and Allowance for Doubtful Accounts. The Partnership's accounts receivable are from purchasers of natural gas, NGLs and crude oil production. The Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by the Partnership's Managing General Partner. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. No allowance was deemed necessary at December 31, 2011 or 2010.

F-7

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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

Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market.

Derivative Financial Instruments. The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and crude oil. The Managing General Partner employs established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. The Managing General Partner's policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

All derivative assets and liabilities are recorded on the balance sheets at fair value. PDC, as Managing General Partner, has elected not to designate any of the Partnership's derivative instruments as hedges. Accordingly, 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 crude oil sales and the realized gain or loss upon the settlement of these instruments are recorded in the line captioned, “Commodity price risk management gain, net.” As positions designated to the Partnership settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the Partnership and net realized losses are deducted from the Partnership's cash distributions generated from production. The Partnership bears its designated share of counterparty risk.

The validation of a contract's fair value is performed by the Managing General Partner. 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 3, Fair Value Measurements and Disclosures and Note 4, 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, 2011 and 2010.

Natural Gas and Crude Oil Properties. The Partnership accounts for its natural gas and crude oil properties (the “Properties”) under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. The Partnership calculates quarterly depreciation, depletion and amortization ("DD&A") expense by using as the denominator the Partnership's estimated quarter-end reserves adjusted to add back current period production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A.See Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited, Net Proved Reserves for additional information regarding the Partnership's reserve reporting. In accordance with the Agreement, all capital contributed to the Partnership after deducting syndication costs and a one-time management fee was used solely for the drilling of natural gas and crude oil wells. The Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of natural gas, NGLs and crude 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 reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas, NGLs and crude 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 represent the Partnership'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 the Partnership's net income.

F-8

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

Proved Property Impairment. The Partnership assesses its producing natural gas and crude 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 Managing General Partner reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of natural gas, NGLs and crude oil. Certain events, including but not limited to, downward revisions in estimates to the Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership's proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows are determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. Due to the availability of new reserve information, the Partnership reviewed its proved natural gas and crude oil properties for impairment at December 31, 2011 and 2010. See Note 10, Impairment of Capitalized Costs for additional disclosure related to the Partnership's proved property impairment.

Production Tax Liability.Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which the Partnership produces natural gas, NGLs and crude oil. The Partnership's share of these taxes is expensed to the account “Natural gas, NGLs and crude 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.

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.

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. Over time, the liabilities are accreted 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, revisions to estimated retirement costs and changes in the estimated timing of settling retirement obligations. See Note 6, Asset Retirement Obligations for a reconciliation of the changes in the Partnership's asset retirement obligation activity.

Revenue Recognition. Natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. The Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of the Partnership's sales when the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells the Partnership's natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by the Partnership's purchasers and reflected in the wellhead price. The majority of the Partnership's natural gas, NGLs and crude oil 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 contract 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.

Recent Accounting Standards.

The following standard was recently adopted:

Fair Value Measurements and Disclosures. In January 2010, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for the Partnership's financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on the Partnership's financial statements.

F-9

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

The following standard was recently issued:

Fair Value Measurement. On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") (collectively the "Boards") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes also require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on the Partnership's financial statements.

NOTE 3 - FAIR VALUE MEASUREMENTS AND DISCLOSURES

Derivative Financial Instruments

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

Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.

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

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Includes the Partnership's natural gas collars.

Derivative Financial Instruments. The Managing General Partner measures the fair value of the Partnership's derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validates its fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

F-10

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

The Managing General Partner has evaluated the credit risk of the counterparties holding the derivative assets, which are primarily financial institutions who are also major lenders in the Managing General Partner's corporate credit facility agreement, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner's evaluation, the Managing General Partner has determined that the impact of the risk of nonperformance of the Managing General Partner's counterparties on the fair value of the Partnership's derivative instruments is insignificant.

The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis.

	December 31, 2011						December 31, 2010 (a)
	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Commodity based derivatives	$	8,675,631	$	236,766	$	8,912,397	$	7,511,512	$	355,842	$	7,867,354
Total assets	8,675,631		236,766		8,912,397		7,511,512		355,842		7,867,354
Liabilities:
Commodity based derivatives	—		—		—		618,004		—		618,004
Basis protection derivative contracts	4,123,062		—		4,123,062		5,519,730		—		5,519,730
Total liabilities	4,123,062		—		4,123,062		6,137,734		—		6,137,734
Net asset	$	4,552,569	$	236,766	$	4,789,335	$	1,373,778	$	355,842	$	1,729,620

(a) The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by $7.5 million) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by $6.1 million). The amounts presented reflect these reclassifications and conform to current period presentation.

F-11

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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

	December 31,
	2011			2010 (1)
Fair value, net asset, beginning of year	$	355,842		$	739,017
Changes in fair value included in statement of operations line item:
Commodity price risk management, net	179,202			641,990
Settlements	(298,278		)	(1,025,165		)
Fair value, net asset, end of year	$	236,766		$	355,842
Change in unrealized gain (loss) relating to assets (liabilities) still held as of
December 31, 2011 and 2010, respectively, included in statement of operations line item:
Commodity price risk management, net	$	136,607		$	324,491

(1) The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by $5.3 million). The amounts presented reflect these reclassifications and conform to current period presentation.

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

Non-Derivative Financial Assets and Liabilities

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

See Note 2, Natural Gas and Crude Oil Properties and Asset Retirement Obligations for a discussion of how we determined fair value for these assets and liabilities.

NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership's results of operations and operating cash flows are affected by changes in market prices for natural gas and crude oil. To manage a portion of the Partnership's exposure to price volatility from producing natural gas and crude oil, the Managing General Partner utilizes an economic hedging strategy for the Partnership's natural gas and crude 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 commodities, 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, 2011, the Partnership had derivative instruments in place for the majority of its anticipated production through 2013 for a total of 2,640,855 MMbtu of natural gas. Partnership policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

The Managing General Partner uses natural gas and crude oil commodity derivative instruments to manage price risk for PDC as well as its sponsored drilling partnerships. The Managing General Partner sets these instruments for PDC and the various partnerships managed by PDC jointly by area of operations, whereby the allocation of derivative positions between PDC and each partnership is set at a fixed quantity. New positions have specific designations relative to the applicable partnership.

F-12

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

As of December 31, 2011, the Partnership's derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis protection swaps.

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

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

• Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty.

The following table presents the location and fair value amounts of the Partnership's derivative instruments on the accompanying balance sheets.

			Fair Value
			December 31,		December 31,
Derivative instruments not designated as hedge(1):		Balance Sheet Line Item	2011		2010
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	5,067,966	$	3,178,313
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives	3,844,431		4,689,041
Total Derivative Assets			8,912,397		7,867,354
Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	—		618,004
	Basis protection contracts	Due to Managing General Partner-derivatives	2,217,809		1,962,839
	Non Current
	Basis protection contracts	Due to Managing General Partner-derivatives	1,905,253		3,556,891
Total Derivative Liabilities			4,123,062		6,137,734
Net fair value of derivative instruments - asset			$	4,789,335	$	1,729,620

⁽¹⁾As of December 31, 2011 and December 31, 2010, none of the Partnership's derivative instruments were designated as hedges.

F-13

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

The following table presents the impact of the Partnership's derivative instruments on the Partnership's accompanying statements of operations.

	Year Ended December 31,
	2011							2010
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains	$	597,469		$	407,562	$	1,005,031	$	519,880		$	2,949,536	$	3,469,416
Unrealized gains (losses)	(597,469		)	3,657,184		3,059,715		(519,880		)	5,200,995		4,681,115
Total commodity price risk management gain, net	$	—		$	4,064,746	$	4,064,746	$	—		$	8,150,531	$	8,150,531

NOTE 5 - CONCENTRATION OF RISK

Accounts Receivable. The Partnership's accounts receivable are from purchasers of natural gas, NGLs and crude oil production. The Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by the Partnership's Managing General Partner. Inherent to the Partnership's industry is the concentration of natural gas, NGL and crude oil sales to a 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 and financial conditions, commodity prices or other conditions.

As of December 31, 2011 and 2010, the Partnership did not record an allowance for doubtful accounts. In making the estimate for receivables that are uncollectible, the Managing General Partner considers, among other things, subsequent collections, historical write-offs and overall creditworthiness of the Partnership's customers. It is reasonably possible that the Managing General Partner's estimate of uncollectible receivables will change periodically. Historically, neither PDC nor any of the other partnerships managed by the Partnership's Managing General Partner have experienced significant losses from uncollectible accounts receivable. The Partnership did not incur any losses on accounts receivable for the years ended December 31, 2011 and 2010.

Major Customers. The following table presents the individual customers constituting 10% or more of total revenues .

	Year ended December 31,
Major Customer	2011	2010
DCP Midstream LP (“DCP”)	13%	14%
Williams Production RMT (“Williams”)	41%	44%
Suncor Energy (USA) Inc. (“Suncor”)	44%	40%

Derivative Counterparties. The Managing General Partner makes use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner's credit facility agreement, as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of the Partnership's derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on this evaluation, the Managing General Partner has determined that the impact of the risk of nonperformance of the counterparties on the fair value of the Partnership's derivative instruments was not significant.

F-14

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 6 −ASSET RETIREMENT OBLIGATIONS

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

	Year Ended December 31,
	2011		2010
Balance at beginning of year	$	727,952	$	680,648
Revisions in estimated cash flows	250,679		—
Accretion expense	52,555		47,304
Balance at end of year	$	1,031,186	$	727,952

In 2011, the Managing General Partner revised its assumptions related to the cash outlay expected to be incurred to plug the Partnership's uneconomic wells.  The revision in the asset retirement obligation did not have an immediate effect in the current year statement of operations, as the increase in the revised obligation will be accreted and the offsetting capitalized amount will be depreciated over the useful lives of respective wells.

NOTE 7 - COMMITMENTS AND CONTINGENCIES

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

Environmental.Due to the nature of the oil and gas industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. During the twelve months ended December 31, 2011, there were no new material environmental remediation projects identified by the Managing General Partner for the Partnership. As of December 31, 2011, the Partnership had accrued environmental remediation liabilities for the Partnership's Piceance Basin wells, in addition to one well in the Wattenberg Field, of approximately $18,000, which is included in line item captioned “Accounts payable and accrued expenses” on the balance sheet. As of December 31, 2010, the Partnership had accrued environmental remediation liabilities for the Partnership's Piceance Basin wells in the amount of approximately $5,000, which is included in line item captioned “Accounts payable and accrued expenses” on the balance sheet. The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2011, which have not been provided for or would otherwise have a material impact on the Partnership's financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership's properties.

NOTE 8 - PARTNERS' EQUITY AND CASH DISTRIBUTIONS

Partners' Equity

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

F-15

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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.

			Managing
	Investor		General
	Partners		Partner
Partnership Revenue:
Natural gas, NGLs and crude 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, NGLs and crude 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 incurred by the Managing General Partner on behalf of the Partnership.

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

Cash Distributions

The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly. The Managing General Partner determines and distributes cash on a monthly basis, if funds are available for distribution. The Managing General Partner makes cash distributions of 63% to the Investor Partners and 37% to the Managing General Partner. Cash distributions began in May 2008. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:

	Year Ended December 31,
	2011		2010
Cash distributions	$	5,410,042	$	14,355,892

Cash distributions to Partners were reduced by the withholding of funds for the Partnership’s future development of proved developed non-producing reserves and proved undeveloped reserves in the amount of $2,000,000 and $120,000 for 2011 and 2010, respectively. Cash distributions to Partners were further decreased in 2011 as compared to 2010 primarily due to the significant decrease in cash flows from operating activities during 2011.

F-16

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 9 - 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 from the Managing General Partner on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership's portion of open derivative instruments is recorded on the balance sheets under the captions “Due from Managing General Partner-derivatives,” in the case of net unrealized gains and “Due to Managing General Partner-derivatives,” in the case of net unrealized losses.

The following table presents transactions with the Managing General Partner reflected in the balance sheet line item - “Due from Managing General Partner-other, net,” which remain undistributed or unsettled with the Partnership's investors as of the dates indicated.

	December 31, 2011			December 31, 2010
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	738,787		$	875,468
Commodity price risk management, realized gain	274,775			478,306
Other (1)	(601,991		)	(819,659		)
Total Due from Managing General Partner-other, net	$	411,571		$	534,115

(1) All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner. The majority of these are operating costs and general and administrative costs which have not been deducted from distributions.

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 4, Derivative Financial Instruments, with the Managing General Partner and its affiliates for the years ended December 31, 2011 and 2010. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the statements of operations.    

	Year Ended December 31,
	2011		2010
Well operations and maintenance (1)	$	3,395,421	$	3,936,833
Gathering, compression and processing fees (2)	406,821		529,849
Direct costs - general and administrative (3)	213,327		200,907
Cash distributions (4)	2,002,528		5,311,680

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

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

Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the 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 and other services for the Partnership at the lesser of cost or competitive prices in the area of operations.

F-17

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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, NGLs and crude 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 natural 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 natural gas.

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

(4) The Agreement provides for the allocation of cash distributions 63% to the Investors Partners and 37% to the Managing General Partner. The Investor Partner cash distributions during 2011 include $812 for Investor Partner units repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 8, Partners’ Equity and Cash Distributions.

F-18

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 10 - IMPAIRMENT OF CAPITALIZED COSTS

The Partnership assesses its proved natural gas and crude 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 Managing General Partner reasonably estimates the commodities to be sold. The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to the Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership's proved natural gas and crude oil properties. If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, as occurred for the year ended December 31, 2010, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. The Partnership's estimated production used in the impairment testing is taken from the annual reserve report (See Supplemental Natural Gas, NGL and Crude Oil Information –Unaudited—Net Proved Reserves). Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. A decline in the forward price curves used to estimate future cash flows at December 31, 2010, accompanied by lower reserves reflected in the Partnership's annual reserve report resulted in an impairment in the fourth quarter of 2010. This downward revision to the future net cash flows resulted primarily from an 8,034 MMcf, or 33.5%, decrease in future estimated natural gas production due to well economics and a reduction in prices from 2009. The Partnership recorded an impairment loss, the first natural gas and crude oil properties impairment recognized by the Partnership since it began operations in 2007, of $27.7 million for the year ended December 31, 2010. The impairment loss resulted from the downward revision to the fair value of discounted future net cash flows of production activities in the Piceance Basin in Colorado. There was no impairment in 2011.

F-19

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited

Net Proved Reserves

The Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. (Ryder Scott), to estimate the Partnership's 2011 and 2010 natural gas, NGLs and crude oil reserves. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. The Partnership's net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of natural gas, NGL and crude oil 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 additional reserve development.

The Partnership's estimated proved developed non-producing and proved undeveloped reserves consist entirely of reserves attributable to the Wattenberg Field's additional development. These additional development activities, which are expected to start in 2012 or later as part of the Additional Development Plan, generally occur five to ten years after initial well drilling. Funding for this additional development work is expected to be provided by withholding distributions from investors. The Managing General Partner began to withhold funds from Partnership distributions in October 2010 for some of the Partnerships, in which they are the Managing General Partner. Funds of $2,120,000 and $2,620,000 have been withheld from this Partnership's distributions as of December 31, 2011 and February 29, 2012, respectively. Currently, the Partnership expects these additional development activities to be completed through approximately 2015. The time frame for development activity is impacted by individual well decline curves as well as the plan to maximize the financial impact of the additional development.

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

	Price Used to Estimate Reserves (1)
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2011	$	87.91	$	3.41	$	31.15
2010	71.08		3.22		37.60

(1) The price used to estimate reserves has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December applied to the Partnership's year-end estimated proved reserves. Prices for each of the two years were adjusted by field for Btucontent, transportation and regional price differences; however, they were not adjusted to reflect the value of the Partnership's commodity derivatives.

F-20

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited

The following table presents the changes in estimated quantities of the Partnership's reserves, all of which are located within the U. S.

	Natural Gas		NGLs		Crude Oil and Condensate		Natural Gas Equivalent
	(MMcf)		(MBbl)		(MBbl)		(MMcfe)
Proved Reserves:
Proved reserves, January 1, 2010	28,089		—		1,184		35,193
Revisions of previous estimates and reclassifications	(5,554	)	494		22		(2,458	)
Production	(2,244	)	(29	)	(81	)	(2,904	)
Proved reserves, December 31, 2010	20,291		465		1,125		29,831
Revisions of previous estimates and reclassifications	(171	)	253		(190	)	207
Production	(1,705	)	(21	)	(56	)	(2,167	)
Proved reserves, December 31, 2011	18,415		697		879		27,871
Proved Developed Reserves, as of:
December 31, 2010	16,983		185		475		20,943
December 31, 2011	17,704		651		776		26,266
Proved Undeveloped Reserves, as of:
December 31, 2010	3,308		280		650		8,888
December 31, 2011	711		46		103		1,605

2011 Activity. At December 31, 2011, the Partnership recorded an upward revision of its previous estimate of proved reserves by approximately 207 MMcfe. The revision includes an upward revision to previous estimates of 253 MBbls of NGLs, partially offset by downward revisions of 171 MMcf of natural gas and 190 MBbls of crude oil. The upward revision for NGLs was primarily due to a higher yield resulting from improved infrastructure as new processing plants were established in the Wattenberg Field area. The downward revisions for natural gas and crude oil were the result of decreased asset performance. Proved undeveloped reserves of 7,283 MMcfe were transferred to proved developed reserves in 2011 due to the reclassification of the Partnership's estimated Wattenberg refracture reserves as a result of the Managing General Partner's determination of the cost of a refracture becoming less significant as compared to the cost of drilling a new well. There were no proved undeveloped reserves developed in 2011.

2010 Activity. At December 31, 2010, the Partnership’s estimated proved reserves experienced a net upward revision of previous estimates of 22 MBbls of crude oil and a net downward revision of previous estimates of 5,554 MMcf of natural gas. Additionally, the Partnership reclassified 494 MBbls of NGLs which were previously included and reported in 2009, with the Partnership’s proved natural gas reserves. These net revisions are the result in part, of revisions to proved developed producing reserves that includes an increase of approximately 6 MBbls of crude oil and a decrease of approximately 5,666 MMcf of natural gas accompanied by an increase of 214 MBbls of NGLs due to the reclassification, previously described. The revisions were primarily due to a decrease in performance projections in the Piceance Basin’s wells that was partially offset by an increase in performance projections in the Wattenberg Field’s wells. The change in field operational performance was accompanied by increased natural gas and crude oil pricing. The revision to proved undeveloped reserves include increases of 16 MBbls of crude oil and 112 MMcf of natural gas accompanied by an increase of 280 MBbls of NGLs due to the reclassification, previously described. The upward revision to proved undeveloped reserves was due in part, to the improved economics resulting from the increase of two well refracturing opportunities scheduled to be completed under the Additional Development Plan, as well as improved economics resulting from somewhat higher twelve-month average natural gas prices and substantially higher twelve-month average crude oil prices in addition to the Wattenberg Field NGLs reserve reclassification. There were no proved undeveloped reserves developed in 2010.

F-21

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited

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

Natural gas and crude oil development costs include costs incurred to gain access to and prepare development well locations for drilling; to drill and equip developmental wells; to complete additional production formations or recomplete existing production formations and to provide facilities to extract, treat, gather and store natural gas and crude oil.

The Partnership is engaged solely in natural gas and crude oil activities, all of which are located in the continental United States. Drilling operations began upon funding in August 2007 and all funds were advanced to the Managing General Partner as of December 31, 2007, for all planned drilling and completion activities. The Partnership owns an undivided working interest in 99 gross (97.9 net) producing natural gas and crude oil wells which includes 75 wells located in the Wattenberg Field within the Denver-Julesburg (“DJ”) Basin, north and east of Denver, Colorado and 24 wells located in the Piceance Basin, situated near the western border of Colorado. In addition to the 99 wells previously mentioned, the Partnership participated in one Piceance Basin developmental well (1.0 net) declared to be a developmental dry hole due to down-hole mechanical failure and was subsequently plugged and abandoned.

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

	As of December 31,
	2011			2010
Leasehold costs	$	2,024,299		$	2,024,299
Development costs	78,236,069			77,910,023
Natural gas and crude oil properties, successful efforts method, at cost	80,260,368			79,934,322
Less: Accumulated depreciation, depletion and amortization	(35,059,637		)	(29,699,641		)
Natural gas and crude oil properties, net	$	45,200,731		$	50,234,681

Included in “Development Costs” are the estimated costs associated with the Partnership's asset retirement obligations discussed in Note 6, Asset Retirement Obligations.

The Partnership recorded an impairment loss, the first natural gas and crude oil properties impairment recognized by the Partnership since it began operations in 2007, of $27,687,418 for the year ended December 31, 2010. Accordingly, the Partnership reduced “Natural gas and crude oil properties” by $39,027,296 and related “Accumulated depreciation, depletion and amortization” for those properties of $11,339,878 for the years ended December 31, 2010. See Note 10, Impairment of Capitalized Costs for additional disclosure related to the Partnership's proved property impairment.

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and crude oil or environmental protection. These amounts totaled approximately $75,000 and $70,000 for 2011 and 2010, respectively.

F-22

EX-31.1

Exhibit 31.1

CERTIFICATION

I, James M. Trimble, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Rockies Region 2007 Limited Partnership:

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present, in all material respects, the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor and the audit committee of the registrant's board of directors (or persons performing the equivalent functions);

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 27, 2012

/s/ James M. Trimble

James M. Trimble

Chief Executive Officer

Petroleum Development Corporation (dba PDC Energy)

Managing General Partner

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Gysle R. Shellum, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Rockies Region 2007 Limited Partnership:

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present, in all material respects, the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor and the audit committee of the registrant's board of directors (or persons performing the equivalent functions);

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 27, 2012

/s/ Gysle R. Shellum

Gysle R. Shellum

Chief Executive Officer
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner

EX-32.1

Exhibit 32.1

CERTIFICATION

In connection with the Quarterly Report of Rockies Region 2007 Limited Partnership (the “Registrant”) on Form 10-Q for the period ended December 31, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned certify pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ James M. Trimble	March 27, 2012
James M. Trimble
Chief Executive Officer
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner
/s/ Gysle R. Shellum	March 27, 2012
Gysle R. Shellum
Chief Financial Officer
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided by the Registrant and will be retained by the Registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

February 2, 2012

PDC Energy

120 Genesis Boulevard

Bridgeport, West Virginia 26330

Gentlemen:

At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain leasehold and royalty interests of PDC Energy's (“PDC”) RR07LP Partnership as of December 31, 2011. The subject properties are located in the state of Colorado. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study completed on February 2, 2012 and presented herein, was prepared for public disclosure by PDC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of RR07LP's total net proved reserves as of December 31, 2011. The third party estimate conducted by Ryder Scott addresses 100 percent of the total proved developed net liquid hydrocarbon reserves, 100 percent of the total proved developed net gas reserves, 100 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 100 percent of the total proved undeveloped net gas reserves of RR07LP.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2011 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

PDC Energy Partnership: RR07LP

As of December 31, 2011
	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate - Barrels	346,626		429,814		102,913		879,353
Plant Products - Barrels	167,628		483,158		45,780		696,566
Gas - MMCF	13,719		3,985		711		18,415
Income Data M$
Future Gross Revenue	$	78,824	$	68,571	$	13,178	$	160,573
Deductions	35,434		26,556		4,757		66,747
Future Net Income (FNI)	$	43,390	$	42,015	$	8,421	$	93,826
Discounted FNI @ 10%	$	27,612	$	19,794	$	2,981	$	50,387

1100 LOUISIANA, SUITE 3800    HOUSTON, TEXAS 77002-5218    TEL (713) 651-9191        FAX (713) 651-0849

1200, 530-8TH AVENUE, S.W.    CALGARY, ALBERTA T2P 358    TEL (403) 262-2799        FAX (403) 262-2790

PDC Energy

February 2, 2012

Page #PageNum#

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of PDC. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 61 percent and gas reserves account for the remaining 39 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income M$
	As of December 31, 2011
Discount Rate		Total
Percent		Proved
5		$66,542
15		$40,015
20		$32,931
25		$27,856

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind-pipe refract categories.

PDC Energy

February 2, 2012

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No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. AtPDC's request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

PDC's operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which PDC RR07LP Partnership owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

PDC Energy

February 2, 2012

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Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The reserve evaluator must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods. Approximately 100 percent of the proved producing reserves attributable to producing wells were estimated by performance methods. The performance method utilized was decline curve analysis which utilized extrapolations of historical production data. The data utilized in this analysis were supplied to Ryder Scott by PDC or obtained from public data sources and were considered sufficient for the purpose thereof.

Approximately 100 percent of the proved undeveloped reserves included herein were estimated by the analogy methods.The data utilized from the existing producing wells to develop analogues were considered sufficient for the purpose thereof.

PDC Energy

February 2, 2012

Page #PageNum#

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

PDC has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by PDC with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, well logs, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by PDC. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by PDC. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

PDC Energy

February 2, 2012

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The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

PDC furnished us with the above mentioned average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us byPDC.The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by PDC to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Avg Benchmark Prices	Avg Realized Prices
United States	Oil/Condensate	WTI Cushing	$96.19/Bbl	$87.91/Bbl
	NGLs	WTI Cushing	$96.19/Bbl	$31.15/Bbl
	Gas	Henry Hub NYMEX	$4.12/MMBTU	$3.41/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

PDC Energy

February 2, 2012

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Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of PDC and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by PDC.No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by PDC and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by PDC were accepted without independent verification.

The proved non-producing and undeveloped reserves in this report have been incorporated herein in accordance with PDC's plans to develop these reserves as of December 31, 2011. The implementation of PDC's development plans as presented to us and incorporated herein is subject to the approval process adopted byPDC's management. As the result of our inquires during the course of preparing this report, PDC has informed us that the development activities included herein have been subjected to and received the internal approvals required by PDC's management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to PDC. Additionally, PDC has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by PDC were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

PDC Energy

February 2, 2012

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Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to RR07LP. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by PDC.

We have provided PDC with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by PDC and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Larry Thomas Nelms is the primary technical person responsible for the estimate of the reserves, future production and income.

Nelms, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1983, is a Managing Senior Vice President and also serves as a member of the Board of Directors, responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Nelms served in a number of engineering positions with Dome Petroleum, Mizel Petro Resources and Exxon. For more information regarding Mr. Nelms' geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Nelms earned a Bachelor of Science degree in Mechanical Engineering from Mississippi State University in 1963 and a Master of Science from the University of New Mexico in 1965, and he is a registered Professional Engineer in the State of Colorado. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, where he serves as chairman of the Denver Section and also served for three years on the board of directors.

As part of his 2009 continuing education hours, Nelms attended an internally presented 16hours of formalized training as well as the day long 2009 RSC Reserves Conference forum, and a presentation at the Denver Section of SPEE by Dr. John Lee relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Nelms serves as the instructor of the PetroSkills course entitled “Oil & Gas Reserve Evaluation” for a period of four years.

Based on his educational background, professional training and more than 25 years of practical experience in the estimation and evaluation of petroleum reserves, Nelms has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

XML

Fair Value Measurements and Disclosures

12 Months Ended

Dec. 31, 2011

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

FAIR VALUE MEASUREMENTS AND DISCLOSURES

Derivative Financial Instruments

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

Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.

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

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Includes the Partnership's natural gas collars.

Derivative Financial Instruments. The Managing General Partner measures the fair value of the Partnership's derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validates its fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

The Managing General Partner has evaluated the credit risk of the counterparties holding the derivative assets, which are primarily financial institutions who are also major lenders in the Managing General Partner's corporate credit facility agreement, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner's evaluation, the Managing General Partner has determined that the impact of the risk of nonperformance of the Managing General Partner's counterparties on the fair value of the Partnership's derivative instruments is insignificant.

The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis.

	December 31, 2011						December 31, 2010 (a)
	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Commodity based derivatives	$	8,675,631	$	236,766	$	8,912,397	$	7,511,512	$	355,842	$	7,867,354
Total assets	8,675,631		236,766		8,912,397		7,511,512		355,842		7,867,354
Liabilities:
Commodity based derivatives	—		—		—		618,004		—		618,004
Basis protection derivative contracts	4,123,062		—		4,123,062		5,519,730		—		5,519,730
Total liabilities	4,123,062		—		4,123,062		6,137,734		—		6,137,734
Net asset	$	4,552,569	$	236,766	$	4,789,335	$	1,373,778	$	355,842	$	1,729,620

(a) The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by $7.5 million) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by $6.1 million). The amounts presented reflect these reclassifications and conform to current period presentation.

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

	December 31,
	2011			2010 (1)
Fair value, net asset, beginning of year	$	355,842		$	739,017
Changes in fair value included in statement of operations line item:
Commodity price risk management, net	179,202			641,990
Settlements	(298,278		)	(1,025,165		)
Fair value, net asset, end of year	$	236,766		$	355,842
Change in unrealized gain (loss) relating to assets (liabilities) still held as of
December 31, 2011 and 2010, respectively, included in statement of operations line item:
Commodity price risk management, net	$	136,607		$	324,491

(1) The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by $5.3 million). The amounts presented reflect these reclassifications and conform to current period presentation.

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

Non-Derivative Financial Assets and Liabilities

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

See Note 2, Natural Gas and Crude Oil Properties and Asset Retirement Obligations for a discussion of how we determined fair value for these assets and liabilities.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management's Estimates

The preparation of the Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires the Partnership to make estimates and assumptions that affect the amounts reported in the Partnership's financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas, natural gas liquids (“NGL” or “NGLs”) and crude oil sales revenue, proved reserves, future cash flows from natural gas and crude oil properties and valuation of derivative instruments.

Basis of Presentation

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

Cash and Cash Equivalents. The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. The balance in the Partnership's account is insured by Federal Deposit Insurance Corporation, or FDIC, up to $250,000 through December 31, 2013. The Partnership has not experienced losses in any such accounts to date and limits the Partnership's exposure to credit loss by placing its cash and cash equivalents with a high-quality financial institution.

Accounts Receivable and Allowance for Doubtful Accounts. The Partnership's accounts receivable are from purchasers of natural gas, NGLs and crude oil production. The Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by the Partnership's Managing General Partner. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. No allowance was deemed necessary at December 31, 2011 or 2010.

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

Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market.

Derivative Financial Instruments. The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and crude oil. The Managing General Partner employs established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. The Managing General Partner's policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

All derivative assets and liabilities are recorded on the balance sheets at fair value. PDC, as Managing General Partner, has elected not to designate any of the Partnership's derivative instruments as hedges. Accordingly, 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 crude oil sales and the realized gain or loss upon the settlement of these instruments are recorded in the line captioned, “Commodity price risk management gain, net.” As positions designated to the Partnership settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the Partnership and net realized losses are deducted from the Partnership's cash distributions generated from production. The Partnership bears its designated share of counterparty risk.

The validation of a contract's fair value is performed by the Managing General Partner. 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 3, Fair Value Measurements and Disclosures and Note 4, 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, 2011 and 2010.

Natural Gas and Crude Oil Properties. The Partnership accounts for its natural gas and crude oil properties (the “Properties”) under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. The Partnership calculates quarterly depreciation, depletion and amortization ("DD&A") expense by using as the denominator the Partnership's estimated quarter-end reserves adjusted to add back current period production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A.See Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited, Net Proved Reserves for additional information regarding the Partnership's reserve reporting. In accordance with the Agreement, all capital contributed to the Partnership after deducting syndication costs and a one-time management fee was used solely for the drilling of natural gas and crude oil wells. The Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of natural gas, NGLs and crude 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 reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas, NGLs and crude 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 represent the Partnership'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 the Partnership's net income.

Proved Property Impairment. The Partnership assesses its producing natural gas and crude 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 Managing General Partner reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of natural gas, NGLs and crude oil. Certain events, including but not limited to, downward revisions in estimates to the Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership's proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows are determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. Due to the availability of new reserve information, the Partnership reviewed its proved natural gas and crude oil properties for impairment at December 31, 2011 and 2010. See Note 10, Impairment of Capitalized Costs for additional disclosure related to the Partnership's proved property impairment.

Production Tax Liability.Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which the Partnership produces natural gas, NGLs and crude oil. The Partnership's share of these taxes is expensed to the account “Natural gas, NGLs and crude 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.

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.

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. Over time, the liabilities are accreted 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, revisions to estimated retirement costs and changes in the estimated timing of settling retirement obligations. See Note 6, Asset Retirement Obligations for a reconciliation of the changes in the Partnership's asset retirement obligation activity.

Revenue Recognition. Natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. The Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of the Partnership's sales when the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells the Partnership's natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by the Partnership's purchasers and reflected in the wellhead price. The majority of the Partnership's natural gas, NGLs and crude oil 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 contract 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.

Recent Accounting Standards.

The following standard was recently adopted:

Fair Value Measurements and Disclosures. In January 2010, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for the Partnership's financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on the Partnership's financial statements.

The following standard was recently issued:

Fair Value Measurement. On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") (collectively the "Boards") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes also require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on the Partnership's financial statements.

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Balance Sheets - December 31,2011 and 2010 Statement (USD $)	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 2,690,377	$ 690,377
Accounts receivable	767,950	1,175,972
Crude oil inventory	47,247	59,031
Due from Managing General Partner-derivatives	5,067,966	3,178,313
Due from Managing General Partner-other, net	411,571	534,115
Total current assets	8,985,111	5,637,808
Natural gas and crude oil properties, successful efforts method, at cost	80,260,368	79,934,322
Less: Accumulated depreciation, depletion and amortization	(35,059,637)	(29,699,641)
Natural gas and crude oil properties, net	45,200,731	50,234,681
Due from Managing General Partner-derivatives	3,844,431	4,689,041
Total noncurrent assets	49,045,162	54,923,722
Total Assets	58,030,273	60,561,530
Current liabilities:
Accounts payable and accrued expenses	95,529	136,704
Due to Managing General Partner-derivatives	2,217,809	2,580,843
Total current liabilities	2,313,338	2,717,547
Due to Managing General Partner-derivatives	1,905,253	3,556,891
Asset retirement obligations	1,031,186	727,952
Total liabilities	5,249,777	7,002,390
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	14,334,835	14,622,934
Limited Partners - 4,470 units issued and outstanding	38,445,661	38,936,206
Total Partners' equity	52,780,496	53,559,140
Total Liabilities and Partners' Equity	$ 58,030,273	$ 60,561,530

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Statements of Cash Flows For the Years Ended December 31, 2011 and 2010 Statement (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Cash flows from operating activities:
Net income (loss)	$ 4,631,398	$ (19,813,716)
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization	5,359,996	9,456,143
Accretion of asset retirement obligations	52,555	47,304
Unrealized gain on derivative transactions	(3,059,715)	(4,681,115)
Loss on impairment of natural gas and crude oil properties	0	27,687,418
Changes in operating assets and liabilities:
Decrease in accounts receivable	408,022	366,833
Decrease (increase) in crude oil inventory	11,784	(24,077)
Decrease in accounts payable and accrued expenses	(41,175)	(57,085)
Decrease in Due from Managing General Partner - other, net	122,544	2,130,851
Net cash provided by operating activities	7,485,409	15,112,556
Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	(75,367)	(70,516)
Net cash used in investing activities	(75,367)	(70,516)
Cash flows from financing activities:
Distributions to partners	(5,410,042)	(14,355,892)
Net cash used in financing activities	(5,410,042)	(14,355,892)
Net increase in cash and cash equivalents	2,000,000	686,148
Cash and cash equivalents, beginning of period	690,377	4,229
Cash and cash equivalents, end of period	2,690,377	690,377
Supplemental disclosure of non-cash activity
Change in asset retirement obligation, with corresponding increase to natural gas and crude oil properties	$ 250,679	$ 0

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General

12 Months Ended

Dec. 31, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

GENERAL

Rockies Region 2007 Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and crude oil properties. Business operations 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”), which conducts business under the name PDC Energy, to conduct and manage the Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of December 31, 2011, there were 1,793 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 37% Managing General Partner ownership in the Partnership. According to the terms of the Limited Partnership Agreement, revenues, costs and cash distributions of the Partnership are allocated 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, 2011, the Managing General Partner has repurchased 5.5 units of Partnership interests from Investor Partners at an average price of $4,577 per unit. As of December 31, 2011, the Managing General Partner owns 37.08% of the Partnership.

The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner's limited partner unit repurchase program, see Note 8, Partners' Equity and Cash Distributions.

Certain reclassifications have been made to the prior period disclosures to conform to the current year presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership's previously reported financial position, cash flows, net income or partners' equity. See Note 3, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership's derivative instruments.

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Condensed Balance Sheet Parenthetical	Dec. 31, 2011	Dec. 31, 2010
Units of Limited Partnership Interest Issued	4,470.00	4,470.00
Units of Limited Partnership Interest Outstanding	4,470.00	4,470.00

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Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2011	Feb. 29, 2012	Jun. 30, 2011
Entity Information [Line Items]
Entity Registrant Name	Rockies Region 2007 LP
Entity Central Index Key	0001407805
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Amendement Flag	false
Entity Common Stock, Share Outstanding		0
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

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Statements of Operations - For the Years Ended December 31, 2011 and 2010 Statement (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Revenues:
Natural gas, NGLs and crude oil sales	$ 10,560,194	$ 14,489,015
Commodity price risk management gain, net	4,064,746	8,150,531
Total revenues	14,624,940	22,639,546
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	4,368,553	5,061,490
Direct costs - general and administrative	213,327	200,907
Depreciation, depletion and amortization	5,359,996	9,456,143
Accretion of asset retirement obligations	52,555	47,304
Loss on impairment of natural gas and crude oil properties	0	27,687,418
Total operating costs and expenses	9,994,431	42,453,262
Income (loss) from operations	4,630,509	(19,813,716)
Interest income	889	0
Net income (loss)	4,631,398	(19,813,716)
Net income (loss) allocated to partners	4,631,398	(19,813,716)
Less: Managing General Partner interest in net income (loss)	1,713,617	(7,331,075)
Net income (loss) allocated to Investor Partners	$ 2,917,781	$ (12,482,641)
Net income (loss) per Investor Partner unit	$ 653	$ (2,793)
Investor Partner units outstanding	4,470.00	4,470.00

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Asset Retirement Obligations Level 1 (Notes)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

ASSET RETIREMENT OBLIGATIONS

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

	Year Ended December 31,
	2011		2010
Balance at beginning of year	$	727,952	$	680,648
Revisions in estimated cash flows	250,679		—
Accretion expense	52,555		47,304
Balance at end of year	$	1,031,186	$	727,952

In 2011, the Managing General Partner revised its assumptions related to the cash outlay expected to be incurred to plug the Partnership's uneconomic wells.  The revision in the asset retirement obligation did not have an immediate effect in the current year statement of operations, as the increase in the revised obligation will be accreted and the offsetting capitalized amount will be depreciated over the useful lives of respective wells.

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Concentration of Risk

12 Months Ended

Dec. 31, 2011

Concentration Risks, Types, No Concentration Percentage [Abstract]

Concentration Risk Disclosure [Text Block]

CONCENTRATION OF RISK

Accounts Receivable. The Partnership's accounts receivable are from purchasers of natural gas, NGLs and crude oil production. The Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by the Partnership's Managing General Partner. Inherent to the Partnership's industry is the concentration of natural gas, NGL and crude oil sales to a 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 and financial conditions, commodity prices or other conditions.

As of December 31, 2011 and 2010, the Partnership did not record an allowance for doubtful accounts. In making the estimate for receivables that are uncollectible, the Managing General Partner considers, among other things, subsequent collections, historical write-offs and overall creditworthiness of the Partnership's customers. It is reasonably possible that the Managing General Partner's estimate of uncollectible receivables will change periodically. Historically, neither PDC nor any of the other partnerships managed by the Partnership's Managing General Partner have experienced significant losses from uncollectible accounts receivable. The Partnership did not incur any losses on accounts receivable for the years ended December 31, 2011 and 2010.

Major Customers. The following table presents the individual customers constituting 10% or more of total revenues .

	Year ended December 31,
Major Customer	2011	2010
DCP Midstream LP (“DCP”)	13%	14%
Williams Production RMT (“Williams”)	41%	44%
Suncor Energy (USA) Inc. (“Suncor”)	44%	40%

Derivative Counterparties. The Managing General Partner makes use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner's credit facility agreement, as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of the Partnership's derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on this evaluation, the Managing General Partner has determined that the impact of the risk of nonperformance of the counterparties on the fair value of the Partnership's derivative instruments was not significant.

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Transactions with Managing General Partner and Affiliates

12 Months Ended

Dec. 31, 2011

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

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 from the Managing General Partner on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership's portion of open derivative instruments is recorded on the balance sheets under the captions “Due from Managing General Partner-derivatives,” in the case of net unrealized gains and “Due to Managing General Partner-derivatives,” in the case of net unrealized losses.

The following table presents transactions with the Managing General Partner reflected in the balance sheet line item - “Due from Managing General Partner-other, net,” which remain undistributed or unsettled with the Partnership's investors as of the dates indicated.

	December 31, 2011			December 31, 2010
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	738,787		$	875,468
Commodity price risk management, realized gain	274,775			478,306
Other (1)	(601,991		)	(819,659		)
Total Due from Managing General Partner-other, net	$	411,571		$	534,115

(1) All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner. The majority of these are operating costs and general and administrative costs which have not been deducted from distributions.

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 4, Derivative Financial Instruments, with the Managing General Partner and its affiliates for the years ended December 31, 2011 and 2010. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the statements of operations.    

	Year Ended December 31,
	2011		2010
Well operations and maintenance (1)	$	3,395,421	$	3,936,833
Gathering, compression and processing fees (2)	406,821		529,849
Direct costs - general and administrative (3)	213,327		200,907
Cash distributions (4)	2,002,528		5,311,680

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

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

Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the 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 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, NGLs and crude 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 natural 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 natural gas.

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

(4) The Agreement provides for the allocation of cash distributions 63% to the Investors Partners and 37% to the Managing General Partner. The Investor Partner cash distributions during 2011 include $812 for Investor Partner units repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 8, Partners’ Equity and Cash Distributions.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

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

Environmental.Due to the nature of the oil and gas industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. During the twelve months ended December 31, 2011, there were no new material environmental remediation projects identified by the Managing General Partner for the Partnership. As of December 31, 2011, the Partnership had accrued environmental remediation liabilities for the Partnership's Piceance Basin wells, in addition to one well in the Wattenberg Field, of approximately $18,000, which is included in line item captioned “Accounts payable and accrued expenses” on the balance sheet. As of December 31, 2010, the Partnership had accrued environmental remediation liabilities for the Partnership's Piceance Basin wells in the amount of approximately $5,000, which is included in line item captioned “Accounts payable and accrued expenses” on the balance sheet. The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2011, which have not been provided for or would otherwise have a material impact on the Partnership's financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership's properties.

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Partners' Equity and Cash Distributions

12 Months Ended

Dec. 31, 2011

Partners' Capital Account, Distributions [Abstract]

Partners' Capital Notes Disclosure [Text Block]

PARTNERS' EQUITY AND CASH DISTRIBUTIONS

Partners' Equity

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

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

			Managing
	Investor		General
	Partners		Partner
Partnership Revenue:
Natural gas, NGLs and crude 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, NGLs and crude 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 incurred by the Managing General Partner on behalf of the Partnership.

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

Cash Distributions

The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly. The Managing General Partner determines and distributes cash on a monthly basis, if funds are available for distribution. The Managing General Partner makes cash distributions of 63% to the Investor Partners and 37% to the Managing General Partner. Cash distributions began in May 2008. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:

	Year Ended December 31,
	2011		2010
Cash distributions	$	5,410,042	$	14,355,892

Cash distributions to Partners were reduced by the withholding of funds for the Partnership’s future development of proved developed non-producing reserves and proved undeveloped reserves in the amount of $2,000,000 and $120,000 for 2011 and 2010, respectively. Cash distributions to Partners were further decreased in 2011 as compared to 2010 primarily due to the significant decrease in cash flows from operating activities during 2011.

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Impairment of Capitalized Costs

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment Impairment or Disposal [Abstract]

Property, Plant and Equipment, Impairment [Policy Text Block]

IMPAIRMENT OF CAPITALIZED COSTS

The Partnership assesses its proved natural gas and crude 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 Managing General Partner reasonably estimates the commodities to be sold. The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to the Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership's proved natural gas and crude oil properties. If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, as occurred for the year ended December 31, 2010, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. The Partnership's estimated production used in the impairment testing is taken from the annual reserve report (See Supplemental Natural Gas, NGL and Crude Oil Information –Unaudited—Net Proved Reserves). Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. A decline in the forward price curves used to estimate future cash flows at December 31, 2010, accompanied by lower reserves reflected in the Partnership's annual reserve report resulted in an impairment in the fourth quarter of 2010. This downward revision to the future net cash flows resulted primarily from an 8,034 MMcf, or 33.5%, decrease in future estimated natural gas production due to well economics and a reduction in prices from 2009. The Partnership recorded an impairment loss, the first natural gas and crude oil properties impairment recognized by the Partnership since it began operations in 2007, of $27.7 million for the year ended December 31, 2010. The impairment loss resulted from the downward revision to the fair value of discounted future net cash flows of production activities in the Piceance Basin in Colorado. There was no impairment in 2011.

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Statement of Partners' Equity - For the Years Ended December 31, 2011 and 2010 (USD $)	Total	Investor Partners	Managing General Partner
Balance at Dec. 31, 2009	$ 87,728,748	$ 60,463,059	$ 27,265,689
Increase (Decrease) in Partners' Capital [Roll Forward]
Distributions to partners	(14,355,892)	(9,044,212)	(5,311,680)
Net income (loss)	(19,813,716)	(12,482,641)	(7,331,075)
Balance at Dec. 31, 2010	53,559,140	38,936,206	14,622,934
Increase (Decrease) in Partners' Capital [Roll Forward]
Distributions to partners	(5,410,042)	(3,408,326)	(2,001,716)
Net income (loss)	4,631,398	2,917,781	1,713,617
Balance at Dec. 31, 2011	$ 52,780,496	$ 38,445,661	$ 14,334,835

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership's results of operations and operating cash flows are affected by changes in market prices for natural gas and crude oil. To manage a portion of the Partnership's exposure to price volatility from producing natural gas and crude oil, the Managing General Partner utilizes an economic hedging strategy for the Partnership's natural gas and crude 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 commodities, 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, 2011, the Partnership had derivative instruments in place for the majority of its anticipated production through 2013 for a total of 2,640,855 MMbtu of natural gas. Partnership policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

The Managing General Partner uses natural gas and crude oil commodity derivative instruments to manage price risk for PDC as well as its sponsored drilling partnerships. The Managing General Partner sets these instruments for PDC and the various partnerships managed by PDC jointly by area of operations, whereby the allocation of derivative positions between PDC and each partnership is set at a fixed quantity. New positions have specific designations relative to the applicable partnership.

As of December 31, 2011, the Partnership's derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis protection swaps.

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

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

• Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty.

The following table presents the location and fair value amounts of the Partnership's derivative instruments on the accompanying balance sheets.

			Fair Value
			December 31,		December 31,
Derivative instruments not designated as hedge(1):		Balance Sheet Line Item	2011		2010
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	5,067,966	$	3,178,313
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives	3,844,431		4,689,041
Total Derivative Assets			8,912,397		7,867,354
Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	—		618,004
	Basis protection contracts	Due to Managing General Partner-derivatives	2,217,809		1,962,839
	Non Current
	Basis protection contracts	Due to Managing General Partner-derivatives	1,905,253		3,556,891
Total Derivative Liabilities			4,123,062		6,137,734
Net fair value of derivative instruments - asset			$	4,789,335	$	1,729,620

⁽¹⁾As of December 31, 2011 and December 31, 2010, none of the Partnership's derivative instruments were designated as hedges.

The following table presents the impact of the Partnership's derivative instruments on the Partnership's accompanying statements of operations.

	Year Ended December 31,
	2011							2010
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains	$	597,469		$	407,562	$	1,005,031	$	519,880		$	2,949,536	$	3,469,416
Unrealized gains (losses)	(597,469		)	3,657,184		3,059,715		(519,880		)	5,200,995		4,681,115
Total commodity price risk management gain, net	$	—		$	4,064,746	$	4,064,746	$	—		$	8,150,531	$	8,150,531