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, 2013

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
(Do not check if a smaller reporting company)

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

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 that is determinable as of the last business day of the registrant's most recently completed second fiscal quarter.

As of February 28, 2014, this Partnership had 4,470 units of limited partnership interest and no units of additional general partnership interest outstanding.

Rockies Region 2007 Limited Partnership

2013 Annual Report on Form 10-K

Table of Contents

		Page
	Part I
Item 1	Business	3
Item 1A	Risk Factors	17
Item 1B	Unresolved Staff Comments	17
Item 2	Properties	17
Item 3	Legal Proceedings	17
Item 4	Mine Safety Disclosures	17
	Part II
Item 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
Item 6	Selected Financial Data	21
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	31
Item 8	Financial Statements and Supplementary Data	32
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	53
Item 9A	Controls and Procedures	53
Item 9B	Other Information	54
	Part III
Item 10	Directors, Executive Officers and Corporate Governance	55
Item 11	Executive Compensation	59
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
Item 13	Certain Relationships and Related Transactions and Director Independence	60
Item 14	Principal Accountant Fees and Services	61
	Part IV
Item 15	Exhibits, Financial Statement Schedules	62
Signatures		64

PART I

WHERE YOU CAN FIND ADDITIONAL INFORMATION

The Rockies Region 2007 Limited Partnership (this “Partnership” or “Registrant”) is subject to the reporting and information requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), 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 this Partnership, which this Partnership electronically files with the SEC. The address of that site is http://www.sec.gov. The Central Index Key ("CIK") for this Partnership is 0001407805. You can read and copy any materials this 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 (800) SEC-0330.

UNITS OF MEASUREMENT

Definitions used throughout the document:

Bbl - One barrel of crude oil or NGLs or 42 gallons of liquid volume.

Boe - One barrel of crude oil equivalent.

Btu - British thermal unit.

MBbl - One thousand barrels of crude oil or NGLs.

MBoe - One thousand barrels of crude oil equivalent.

Mcf - One thousand cubic feet of natural gas volume.

MMcf - One million cubic feet of natural gas volume.

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 and Section 21E of the Securities Exchange Act of 1934 regarding this Partnership's business, financial condition and results of operations. PDC Energy, Inc. (“PDC”) is the Managing General Partner of this Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements may relate to, among other things: estimated crude oil, natural gas and natural gas liquids ("NGLs") reserves; additional development plans; future production (including the components of such production), sales, expenses, cash flows and liquidity; anticipated capital expenditures and projects; availability of additional midstream facilities and services, timing of that availability and related benefits to this Partnership; the impact of high line pressures; and the Managing General Partner's future strategies, plans and objectives.

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

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

• changes in worldwide production volumes and demand, including economic conditions that might impact demand;

• volatility of commodity prices for crude oil, natural gas and NGLs;

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

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

• changes in estimates of proved reserves;

• inaccuracy of reserve estimates and expected production rates;

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

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

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

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

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

• timing and receipt of necessary regulatory permits;

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

• future cash flows, liquidity and financial condition;

• competition within the oil and gas industry;

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

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

• cost of pending or future litigation;

• adjustments relating to asset dispositions that may be unfavorable to this Partnership;

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

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

Further, this Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this Annual Report on Form 10-K and this Partnership's other filings with the SEC for further information on risks and uncertainties that could affect this Partnership's business, financial condition, results of operations and cash flows. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. This Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement.

2

ITEM 1. BUSINESS

General Information

This Partnership is a privately subscribed West Virginia Limited Partnership which owns an undivided working interest in wells located in Colorado, from which this Partnership produces and sells crude oil, natural gas and NGLs. This 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 this Partnership's capital, or equity interests (which are sometimes referred to as units). PDC, a Nevada corporation, is the Managing General Partner and owns the remaining 37% of this Partnership's equity interests. Upon funding, this Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner that governs the drilling and operational aspects of this Partnership. In accordance with the Limited Partnership Agreement (“Agreement”), general partnership interests were converted to limited partnership units at the completion of this Partnership's drilling activities. This Partnership expended substantially all of the capital raised in the offering for the initial drilling and completion of this Partnership's wells.

Upon request of an individual investor partner, the Managing General Partner may, under certain circumstances provided for in the Agreement, repurchase Investor Partner units. 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 this Partnership as of the date of filing, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

This Partnership expects to continue to operate its crude oil and natural gas properties until such time this Partnership's wells are depleted or become uneconomical to produce, at which time that well may be sold or plugged, reclaimed and abandoned. This Partnership's maximum term of existence extends through December 31, 2057, unless dissolved in certain circumstances stipulated in 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 this Partnership's and PDC's principal executive offices are 1775 Sherman Street, Suite 3000, Denver, Colorado 80203 and (303) 860-5800.

PDC-Sponsored Drilling Program Acquisition Plan

As managing general partner of various limited partnerships, PDC has disclosed its intention to pursue, beginning in the fall of 2010, the acquisition of the limited partnership units held by limited partners other than PDC or its affiliates, (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership (the “Acquisition Plan”). 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.

During 2010 and 2011, PDC purchased 12 partnerships for an 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 additional development in the Wattenberg Field, including commodity prices; and SEC reporting compliance status and timing and the ability to achieve all necessary SEC approvals required to commence a merger and repurchase offer. There is no assurance that any potential proposed repurchase offer to any other of PDC's various limited partnerships, including this Partnership, will occur.

3

In December 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 the partnership repurchases completed by mergers in 2010 and 2011. The action was filed in United States District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp. The complaint primarily alleges a claim that the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. On February 10, 2012, PDC filed a motion to dismiss, or in the alternative, to stay. In June 2012, the Court denied the motion. In January 2014, the plaintiffs were conditionally certified as a class by the court. A jury trial is scheduled for May 2014.

Business Strategy

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

This Partnership's business plan going forward, including the Additional Development Plan described below, is to produce and sell the crude oil, natural gas and NGLs from this Partnership's wells, and to make distributions to the partners as outlined in this 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 each Partnership well was "completed" (i.e., drilled, fractured or stimulated, and with all surface production equipment and pipeline facilities necessary to produce the well installed), production operations commenced on the well. All Partnership wells have been completed and production operations are currently being conducted with regard to each of this Partnership's productive wells.

PDC, in accordance with the D&O Agreement, is the named operator of record of this Partnership's wells and may, in certain circumstances, provide equipment and supplies, and perform salt water disposal and other services for this Partnership. Generally, equipment and services are sold to this Partnership at the lower of cost or competitive prices in the area of operations. This 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, this Partnership records a liability to PDC. The Managing General Partner considers the cash available for distributions to be this Partnership's net cash flows from operating activities, less any net cash used in capital activities.

Area of Operations

Wattenberg Field, Denver-Julesburg Basin, Colorado. This Partnership operates in the Wattenberg Field, located north and east of Denver, Colorado. Its 75 wells in this field exhibit production histories typical for other vertical 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. Production in this field includes natural gas, NGLs and/or crude oil. Of this 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, this Partnership also completed wells, including one Dakota formation well and five J-Sand formation wells, that currently produce from deeper formations. This Partnership's wells in this area are generally 6,500 to 7,500 feet in depth.

Strategic Divestiture

Piceance Basin, Colorado. In June 2013, this Partnership completed the sale to Caerus Oil and Gas LLC (“Caerus”) of all of its Piceance Basin assets and certain derivatives for total consideration of approximately $13.5 million. The divestiture resulted in a decrease of crude oil and natural gas properties of $23.8 million and a decrease of accumulated depreciation, depletion and amortization of $10.3 million. The sale also resulted in a loss on divestiture of assets of approximately $0.5 million. In July 2013, this Partnership distributed the proceeds from the sale to the partners.

4

Title to Properties

This Partnership's leases are direct interests in producing properties. This Partnership believes it holds good and defensible title to its crude oil and natural gas properties, in accordance with standards generally accepted in the industry, through the record title held in this Partnership's name, of each Partnership well's working interest. This 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 which are likely to materially interfere with the commercial use of its properties. Provisions of the Agreement generally relieve the Managing General Partner of liability for errors in judgment with respect to the waiver of title defects.

Drilling and Other Development Activities

Crude Oil and Natural Gas Properties. This Partnership's properties consist of a working interest in the well bore in each well drilled by this Partnership. This Partnership drilled 100 wells (98.9 net) (the net number being the number of gross wells multiplied by the working interest in the wells owned by this Partnership) during drilling operations that began immediately after funding and concluded in September 2008 when the last of this 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 this Partnership. The 100 wells discussed above are the only wells to be drilled by this Partnership since all of the funds raised in this Partnership's offering have been expended. This Partnership's Piceance Basin assets were divested in June 2013.

Productive wells consist of producing wells and wells capable of producing crude oil, natural gas and NGLs in commercial quantities. The following table presents the number of this Partnership's productive wells by locationas of December 31, 2013 and 2012:

	Productive Natural Gas Wells
	2013		2012
Location	Gross	Net	Gross	Net
Wattenberg Field	75.0	73.9	75.0	73.9
Piceance Basin (1)	—	—	24.0	24.0
Total Productive Wells	75.0	73.9	99.0	97.9

(1) In June 2013, this Partnership's Piceance Basin crude oil and natural gas properties were divested. See Note 11, Divestiture and Discontinued Operations, to this Partnership's financial statements included elsewhere in this report for additional information regarding this divestiture.

Additional Development Plan. The Managing General Partner has begun executing a plan for this Partnership's Wattenberg Field wells, that may provide for additional reserve development of crude oil, natural gas and NGLs production (the “Additional Development Plan”). The Additional Development Plan contemplates refracturing of wells currently producing in the Codell formation and/or recompletion of wells in the Niobrara or Codell formations which are currently not producing. 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. Historically, refracturing and recompletion activities have resulted in an increase in both liquids and natural gas production.

5

Additional development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to 10 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 that are believed to provide an attractive rate of return to this Partnership. On average, past PDC refracturings or recompletions have increased production; however, not all past refracturings or recompletions have been economically successful and similar future refracturing or recompletion activities may not be economically successful. If the additional development work is performed, this 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 this 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 this Partnership's net cash flows from operating activities, less any net cash used in capital activities.

The Agreement permits this 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 Additional Development Plan's well refracturings or recompletions, or any subsequent refracturings or recompletions, through bank borrowing. In the event that this Partnership's refracturing or recompletion activities are funded in part through borrowing, potential cash available for distributions derived from production increases provided by the additional development of this Partnership's Wattenberg Field wells may not be sufficient to repay this Partnership's borrowing obligations, which will include principal and interest. Borrowings, if any, will be non-recourse to the Investor Partners. Accordingly, this Partnership, not the Investor Partners, will be responsible for loan repayment. However, any bank borrowings may be collateralized by this Partnership's assets and may restrict distributions as long as there is a balance due on any loan.

Current estimated costs for these well refracturings or recompletions are typically between $180,000 and $260,000 per activity. As of December 31, 2013, this Partnership has approximately 48 additional development opportunities remaining. Total withholding for these activities from this Partnership's cash available for distributions is estimated to be between $8.6 million and $12.5 million, if all of the activities are performed. The Managing General Partner will continually evaluate the timing of the additional development activities based on engineering data and a favorable commodity price environment in order to maximize the expected financial benefit of the additional well development. See Financial Condition, Liquidity and Capital Resources − Cash Flows, for costs incurred for well refracturings or recompletions in 2013 and 2012.

This Partnership's Wattenberg Field production was adversely impacted by high line pressures on the gathering system operated by DCP Midstream during the spring and summer months of 2012 and 2013. The Managing General Partner, and other operators in the field, are working with DCP Midstream in the Wattenberg Field, which is implementing a multi-year facility expansion program. The program is increasing midstream system capacity and helping to mitigate the impact of increased production volumes on system pressures. Although the Managing General Partner expects system pressures to fluctuate and constrain production from time to time, the Managing General Partner believes that this expansion will provide the additional gathering and processing capacity in the system necessary to increase the Managing General Partner's confidence that this Partnership can continue to produce and market this Partnership's production.

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. However, due to the limitations in the take away capacity noted above and the extended timeline anticipated for the curtailments, the projected rates of return for refracturing and recompletion activities have significantly deteriorated. Therefore, during 2012 PDC elected to temporarily suspended the Additional Development Plan and the withholding of funds designated for this development until the high line pressure situation improves and stabilizes. Unspent funds of $329,000 previously withheld from distributions pursuant to the Additional Development Plan were distributed during the fourth quarter of 2012 based upon each partner's proportional ownership interest. It is currently anticipated that withholding will recommence sometime in late 2014 or 2015, if the expected improvement in high line pressures is successful. Based on these expectations, this program will materially reduce, up to 100%, cash available for distributions of this Partnership for a period of time not expected to exceed five years. However, no assurance can be given when the Additional Development Plan will recommence, if at all.

6

Proved Reserves

This Partnership's proved reserves are sensitive to future crude oil, natural gas and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in recognition of more economically viable proved undeveloped reserves. Decreases in commodity prices may result in negative impacts of this nature.

All of this Partnership's proved reserves are located onshore in the U.S. This Partnership's proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and applicable SEC staff regulations, interpretations and guidance. As of December 31, 2013, all of this Partnership's proved reserves have been estimated by Ryder Scott Company, L.P. (“Ryder Scott”), the Managing General Partner's independent petroleum engineering consulting firm.

The Managing General Partner has established a comprehensive process that governs the determination and reporting of this Partnership's proved reserves. As part of the Managing General Partner's internal control process, this Partnership's reserves are reviewed annually by an internal team composed of reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data as well as production performance data. The process includes a review of applicable working and net revenue interests and cost and performance data. The internal team compiles the reviewed data and forwards the data to the independent engineering firm engaged to estimate this Partnership's reserves.

This Partnership's proved reserve estimates as of December 31, 2013 were based on a reserve report prepared by Ryder Scott. When preparing this Partnership's reserve estimates, Ryder Scott 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.

Ryder Scott prepared an estimate of this 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 pursuant to acceptable industry methods and with a level of detail the Managing General Partner deems appropriate. The final estimated reserve report was reviewed by the Managing General Partner's engineering staff and management prior to issuance by Ryder Scott.

The professional qualifications of the Managing General Partner's internal lead engineer primarily responsible for overseeing the preparation of this Partnership's reserve estimates qualify the engineer as a 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 position is currently being held by an employee of the Managing General Partner who holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 36 years of experience in reservoir engineering, 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 as defined in SEC Regulation S-X Section 4-10(a) refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. This 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. All of this Partnership's proved reserves are proved developed reserves. Proved developed reserves are quantities of crude oil, natural gas and NGLs expected to be recovered through existing wells with existing equipment and operating methods.

The SEC's reserve rule has expanded the technologies that a registrant may use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

7

This Partnership used a combination of production and pressure performance, wireline wellbore measurements, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate this Partnership's reserve estimates.

Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. See Item 8, Financial Statements and Supplemental Data - Net Proved Reserves for additional information regarding this Partnership's reserves. As of December 31, 2013 and 2012, there were no proved undeveloped reserves for this Partnership.

The following table provides information regarding this Partnership's estimated proved reserves:

	As of December 31,
	2013	2012 (1)
Proved Reserves
Natural Gas (MMcf)	4,716	13,036
Crude Oil and Condensate (MBbl)	668	853
NGLs (MBbl)	499	595
Total proved reserves (MBoe)	1,953	3,621

(1) Includes estimated reserve data related to this Partnership's Piceance Basin assets, which were divested in June 2013. See Note 11, Divestiture and Discontinued Operations, to this Partnership's financial statements included elsewhere in this report for additional details related to the divestiture of this Partnership's Piceance Basin assets.

The following tables present this Partnership's estimated proved reserves by type and by field:

	As of December 31, 2013
			Crude Oil and	Crude Oil
	Natural Gas	NGLs	Condensate	Equivalent
	(MMcf)	(MBbl)	(MBbl)	(MBoe)	Percent
Proved reserves
Wattenberg Field	4,716	499	668	1,953	100	%
Total proved reserves	4,716	499	668	1,953	100	%
	As of December 31, 2012
			Crude Oil and	Crude Oil
	Natural Gas	NGLs	Condensate	Equivalent
	(MMcf)	(MBbl)	(MBbl)	(MBoe)	Percent
Proved reserves
Piceance Basin (1)	7,390	—	17	1,249	34	%
Wattenberg Field	5,646	595	836	2,372	66	%
Total proved reserves	13,036	595	853	3,621	100	%

(1) Represents estimated reserve data related to this Partnership's Piceance Basin assets, which were divested in June 2013. See Note 11, Divestiture and Discontinued Operations, to this Partnership's financial statements included elsewhere in this report for additional details related to the divestiture of this Partnership's Piceance Basin assets.

8

Production, Sales, Prices and Lifting Costs by Field

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

	Year ended December 31,
	2013		2012
Production (1)
Crude Oil (Bbl)
Piceance Basin (2)	1,513		2,726
Wattenberg Field	51,256		57,782
Total Crude Oil	52,769		60,508
Natural gas (Mcf)
Piceance Basin (2)	516,160		1,231,342
Wattenberg Field	217,750		221,754
Total Natural Gas	733,910		1,453,096
NGLs (Bbl)
Wattenberg Field	21,712		20,830
Crude oil equivalent (Boe)
Piceance Basin (2)	87,540		207,949
Wattenberg Field	109,260		115,572
Total crude oil equivalent	196,800		323,521
Crude Oil, Natural Gas and NGLs Sales
Crude oil sales
Piceance Basin (2)	$	119,511	$	212,451
Wattenberg Field	4,648,840		4,986,162
Total crude oil sales	4,768,351		5,198,613
Natural gas sales
Piceance Basin (2)	1,652,450		2,144,091
Wattenberg Field	688,604		541,638
Total natural gas sales	2,341,054		2,685,729
NGLs sales
Wattenberg Field	365,499		376,916
Crude oil, natural gas and NGLs sales
Piceance Basin (2)	1,771,961		2,356,542
Wattenberg Field	5,702,943		5,904,716
Total crude oil, natural gas and NGLs sales	$	7,474,904	$	8,261,258
Average Selling Price (excluding net settlements on derivatives)
Crude Oil (per Bbl)
Piceance Basin (2)	$	78.99	$	77.94
Wattenberg Field	90.70		86.29

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	Year ended December 31,
	2013		2012
Weighted-average selling price crude oil	90.36		85.92
Natural gas (per Mcf)
Piceance Basin (2)	$	3.20	$	1.74
Wattenberg Field	3.16		2.44
Weighted-average selling price natural gas	3.19		1.85
NGLs (per Bbl)
Wattenberg Field	$	16.83	$	18.09
Crude oil equivalent (per Boe)
Piceance Basin (2)	$	20.24	$	11.33
Wattenberg Field	52.20		51.09
Weighted-average selling price crude oil equivalent	37.98		25.54
Average Production (Lifting) Cost (per Boe) (3)
Piceance Basin (2)	$	7.05	$	7.57
Wattenberg Field	10.63		8.87
Weighted-average production cost	9.04		8.04

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

(2) In June 2013, this Partnership's Piceance Basin oil and gas properties were divested. See Note 11, Divestiture and Discontinued Operations, to this Partnership's financial statements included elsewhere in this report for additional information regarding this divestiture.

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

For more information concerning this Partnership's production volumes and costs, which include severance and ad valorem taxes as reflected in this 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.

Crude Oil, Natural Gas and NGLs Sales

In accordance with the D&O Agreement, PDC markets the crude oil, natural gas and NGLs produced from this Partnership's wells. PDC does not charge an additional fee for the marketing of the crude oil, natural gas and NGLs because these services are covered by the monthly well operating charge. This monthly charge is more fully described in Item 1, Business - Reliance on the Managing General Partner - Provisions of the D&O Agreement.

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• Crude oil. This Partnership does not refine any of its crude oil production. Crude oil is sold at each individual well site and transported by the purchasers via truck, pipeline or rail to local and non-local markets under various purchase contracts with monthly pricing provisions based on a differential to the average monthly New York Mercantile Exchange ("NYMEX") price. This Partnership currently has no long-term firm transportation agreements related to its crude oil production.

• Natural gas. This Partnership primarily sells its natural gas to midstream marketers. The Managing General Partner generally sells the natural gas that this Partnership produces under contracts with Colorado Interstate Gas ("CIG") monthly pricing provisions. Virtually all of this Partnership's contracts include provisions whereby prices change monthly with changes in the market, with certain adjustments that may be made based on whether a well delivers to a gathering or transmission line and the quality of the natural gas. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. The Managing General Partner believes that the pricing provisions of this Partnership's natural gas contracts are customary in the industry.

• NGLs. The majority of this Partnership's NGLs are sold at the tailgate of DCP Midstream processing plants based on prices of NGL deliveries to the Conway hub in Kansas. This Partnership's NGLs production is sold under long-term purchase contracts.

Transportation and Gathering

This Partnership's natural gas is transported through the Managing General Partner's and third-party gathering systems and pipelines, and this Partnership incurs processing, gathering and transportation costs to move this Partnership's natural gas from the wellhead to a purchaser-specified delivery point. These costs vary based upon the volume and distance shipped, as well as the fee charged by the third-party processor or transporter. Like most producers, this Partnership relies on third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with production growth. As a result, the timing and availability of additional facilities going forward is beyond this Partnership's or the Managing General Partner's control. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable due to operational issues, repairs or improvements. A portion of this Partnership's natural gas is transported under interruptible contracts and the remainder under firm transportation agreements through third-party processors or marketers. Therefore, interruptions in natural gas sales could result if pipeline space is constrained. If transportation space is restricted or is unavailable, this Partnership's production and cash flows from the affected properties could be adversely affected.

Wattenberg Field production was adversely impacted by high line pressures on the gathering system operated by DCP Midstream during the spring and summer months of 2012 and 2013. The Managing General Partner, and other operators in the field, are working with this Partnership's primary midstream provider in the Wattenberg Field, who is implementing a multi-year facility expansion program. The program is increasing midstream system capacity and helping to mitigate the impact of increased production volumes on system pressures. Although the Managing General Partner expects system pressures to fluctuate and constrain production from time-to time, the Managing General Partner believes that this expansion will provide the additional gathering and processing capacity in the system necessary to market this Partnership's production from continuing operations.

This Partnership's crude oil production is stored in tanks at or near the location of this Partnership's wells for periodic 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 this Partnership ultimately receives for the crude oil.

Commodity Price Risk Management Activities

Prior to July 2013, the Managing General Partner, on behalf of this Partnership in accordance with the D&O Agreement, utilized commodity based derivative instruments to manage a portion of this Partnership's exposure to price volatility with regard to this Partnership's crude oil and natural gas sales. In June 2013, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated or sold to Caerus. Accordingly, as of December 31, 2013, this Partnership did not have any derivative instruments in place for its future production. The financial instruments generally consisted of collars, swaps and basis swaps and were NYMEX-traded and CIG-based contracts. The contracts provided a degree of price stability for committed and anticipated crude oil and natural gas sales. This 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 used financial derivatives to establish "floors" and "ceilings" or "collars" on the possible range of the prices realized for the sale of crude oil and natural gas in addition to fixing prices by using swaps. These derivatives were carried on the balance sheets at fair value with changes in fair values recognized in the statement of operations. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Commodity Price Risk Management for additional information on net settlements of derivatives for the years ended December 31, 2013 and 2012.

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This Partnership is subject to price fluctuations for crude oil and natural gas sold in the spot market and under market index contracts. In accordance with the D&O Agreement, the Managing General Partner may enter into derivative arrangements on behalf of this Partnership. The Managing General Partner has not entered into such arrangements on behalf of this Partnership in the last few years and does not anticipate entering into additional commodity based derivative instruments on behalf of this Partnership; however, this could change in the future.

Governmental Regulation

While the prices of crude oil and natural gas are market driven, other aspects of this Partnership's business and the industry in general are heavily regulated. The availability of a ready market for crude oil and natural gas production depends on several factors that are beyond this Partnership's control. These factors include, but are not limited to, regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of crude oil and natural gas 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, reduce environmental and health risks from the development and transportation of crude oil and natural gas, prevent misuse of crude oil and natural gas and protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The Managing General Partner believes that it is in compliance with such statutes, rules, regulations and governmental orders, in all material respects, although there can be no assurance that this is or will remain the case. The following summary discussion on 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 directives to which this Partnership's operations may be subject.

Regulation of Crude Oil and Natural Gas Production. This Partnership's production business is subject to various federal, state and local laws and regulations on the taxation of crude oil and natural gas, the development, production and marketing of crude oil and natural gas and environmental and safety matters. State and local laws and regulations require drilling permits and govern the spacing and density of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing refracturing 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 being 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;

• fluid disposal; and

• air emissions.

In addition, this 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.

The Partnership's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of lands and leases. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units, and therefore, more difficult to drill and develop our leases where we own less than 100% of the leases located within the proposed unit. State laws may establish maximum rates of production from crude oil and natural gas wells, prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Leases covering state or federal lands often include additional regulations and conditions. The effect of these conservation laws and regulations may limit the amount of crude oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our crude oil and natural gas wells and other facilities. These laws and regulations, and any others that are passed by the jurisdictions where we have production, can limit the total number of wells drilled or the allowable production from successful wells, which can limit our reserves. As a result, the Managing General Partner is unable to predict the future cost or effect of complying with such regulations.

Regulation of Transportation of Natural Gas. The Managing General Partner moves natural gas through pipelines owned by other companies, and sells natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC")

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under the Natural Gas Act of 1938 ("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 jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by 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.

Each interstate natural gas pipeline company establishes its rates primarily through 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 this Partnership's natural gas sales. Competition among suppliers has greatly increased. Furthermore, gathering is exempt from regulation under the Natural Gas Act, thus allowing gatherers to charge unregulated 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 current regulatory approach recently taken by FERC and Congress will continue. The Managing General Partner cannot determine to what extent this 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

This 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 demand for 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 which restrict drilling or impose environmental protection requirements resulting in increased costs, this Partnership's business and prospects may be adversely affected.

This Partnership generates waste that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("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 this 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 this Partnership to more rigorous and costly operating and disposal requirements.

Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. This Partnership would apply fracturing in any 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 has asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA") and issued draft guidance related to this asserted regulatory authority in February 2014. The guidance explains the EPA’s interpretation of the term “diesel fuel” for permitting purposes, describes existing Underground Injection Control Class II program requirements for permitting underground injection of diesel fuels in hydraulic fracturing and also provides recommendations for EPA permit writers in implementing these requirements. From time to time, Congress has considered legislation that would provide for federal regulation of hydraulic fracturing and disclosure of the chemicals used in the hydraulic fracturing process.

The White House Council on Environmental Quality continues to coordinate an administration-wide review of hydraulic fracturing. The EPA continues its study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected by December 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

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completion methods. 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 mechanisms. The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), is also conducting a rulemaking to require disclosure of chemicals used, mandate well integrity measures and impose other requirements relating to hydraulic fracturing on federal lands.

Colorado has adopted and is considering additional regulations that could impose more stringent permitting, transparency and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Colorado requires that all chemicals used in the hydraulic fracturing of a well be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission ("Frac Focus"). The Colorado rules also require operators seeking new location approvals to provide certain information to surface owners and adjacent property owners within 500 feet of a new well. Similarly, Colorado has implemented a baseline groundwater sampling rule and a rule governing setback distances of oil and gas wells located near population centers. In December 2013, the Colorado Oil and Gas Conservation Commission issued new, more restrictive rules regarding spill reporting and remediation.

In Colorado, local governing bodies have begun to issue drilling moratoriums, develop jurisdictional siting, permitting and operating requirements, and conduct air quality studies to identify potential public health impacts. For instance, in 2013 the City of Fort Collins, Colorado, adopted a ban on drilling and fracturing of new wells within city limits. In the November 2013 election, voters in the cities of Boulder, Lafayette, Fort Collins, and Brighton passed hydraulic fracturing bans. This Partnership does not currently have operations in any of these areas. In addition, a ballot initiative has been proposed in Colorado which, if approved and upheld, could greatly expand the right of local governments to limit or prohibit oil and natural gas production and development in their jurisdictions. If new laws or regulations that significantly restrict hydraulic fracturing or well locations continue to be adopted at local levels or are adopted at the state level, such laws could make it more difficult or costly for this Partnership 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 this Partnership's ability to execute the Additional Development Plan. If hydraulic fracturing becomes regulated as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, this 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 this Partnership is ultimately able to produce from its reserves. The Managing General Partner continues to be active in stakeholder and interest groups and to engage with regulatory agencies in an open, proactive dialogue.

This Partnership currently owns properties that for many years have been used for the exploration and production of crude oil and natural gas. Although this Partnership believes that this 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 this 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 ("CERCLA"), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. Under such laws, this 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 crude oil and natural gas wells, this Partnership may be liable pursuant to CERCLA and similar state laws.

This Partnership's operations are subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from this Partnership's operations. The EPA and states continue the development of regulations to implement these requirements. This 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. Federal New Source Performance Standards regarding oil and gas operations ("NSPS OOOO") became effective in 2012 and 2013, with additional NSPS provisions expected

14

in 2014, all of which will add administrative and operational costs. Colorado continues to draft and adopt new regulations to meet the requirements of NSPS OOOO and will promulgate significant rules relating specifically to crude oil and natural gas operations that are more stringent than NSPS OOOO and are expected to be finalized by March 2014.

The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction where construction will disturb wetlands or other waters of the U.S. The CWA also regulates storm water run-off from crude oil and natural gas 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, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013, which determined that all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of new rules regarding what will be considered waters of the U.S. The new rules were submitted for inter-agency review in October 2013 and are expected to be available for public review by May 2014.

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 this Partnership, to procure and implement additional SPCC measures relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990 ("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, this Partnership has not experienced any significant crude oil discharge or crude oil spill problems.

This Partnership's costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2014 and beyond. Environmental regulations have increased this Partnership's costs and planning time, but have had no materially adverse effect on this Partnership's ability to operate to date. However, 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 this Partnership's business, financial condition or results of operations. See Note 7, Commitments and Contingencies, to this Partnership's financial statements included elsewhere in this report.

Competition and Technological Changes

The Managing General Partner believes that this Partnership's production capabilities and the experience of PDC's management and professional staff generally enable this Partnership to compete effectively. This Partnership encounters competition from numerous crude oil and natural gas companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing crude oil and natural gas. This Partnership faces intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possibility of improved economics of domestic exploration activities may influence other companies to increase their domestic crude oil and natural gas exploration.

Recently, certain regions experienced strong demand for drilling services and supplies, which resulted in increasing costs. Factors affecting competition in the industry include price, location of drilling, availability of drilling prospects and drilling rigs, fracturing services, pipeline capacity, quality of production and volumes produced. This Partnership's business, financial condition and results of operations could be materially adversely affected by competition.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies that this Partnership uses now or in the future were to become obsolete or if the Managing General Partner is unable to use the most advanced commercially available technology, this Partnership's business, financial condition, results of operations and cash flows could be materially adversely affected.

Reliance on Managing General Partner

General. As provided by the Agreement, PDC, as Managing General Partner, has authority to manage this Partnership's activities through the D&O Agreement, utilizing its best efforts to carry out the business of this 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 this Partnership, while technical geosciences and petroleum engineering staff oversee the well drilling, completions, recompletions and operations. PDC's administrative staff controls this 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.

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Provisions of the D&O Agreement. Under the terms of the D&O Agreement, this Partnership has authorized and extended to PDC the authority to manage the production operations of the crude oil and natural gas wells in which this 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, this Partnership has the right to take in-kind and separately dispose of its share of all crude oil, natural gas and NGLs produced from this Partnership's wells. This Partnership designated PDC as its crude oil, natural gas and NGLs production marketing agent and authorized PDC to enter into and bind this Partnership, under those agreements PDC deems in the best interest of this Partnership, in the sale of this Partnership's crude oil, natural gas and NGLs. Generally, PDC has limited liability to this 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 this 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, this Partnership pays only its proportionate share of total lease and development costs, pays only this Partnership's proportionate share of operating costs and receives its proportionate share of production subject only to royalties and overriding royalties.

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

Operating Hazards and Insurance. This Partnership's production operations include a variety of operating risks including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of crude oil and natural gas. The occurrence of any of these could result in substantial losses to this Partnership 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. This 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.

PDC, in its capacity as Managing General Partner and operator, has purchased various insurance policies and lists this Partnership as a named insured on certain of those policies, including workers' 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 increase or decrease policy limits, change types of insurance and name PDC and this Partnership, individually or together, parties to the insurance as deemed appropriate under the circumstances, which may vary materially. As operator of this 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 this 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.

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Any significant problems related to this Partnership's facilities could adversely affect this Partnership's ability to conduct operations. This 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, this Partnership is not insured against economic losses resulting from damage or destruction to third-party property, such as transportation pipelines, crude oil refineries or natural gas processing facilities. Such an event could result in significantly lower regional prices or a reduction in this Partnership's ability to deliver its production. In addition, some pollution-related risks are not insurable.

Customers. PDC markets the crude oil, natural gas and NGLs from Partnership wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of this Partnership. Currently, PDC sells its natural gas and NGLs production 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 this Partnership's wells to DCP are made on the spot market via open-access transportation arrangements through pipelines and may be impacted by capacity interruptions on pipelines transporting natural gas out of the region.

This Partnership's crude oil production is sold at or near this Partnership's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry. Oil prices fluctuate not only with the general market for oil as may be indicated by changes in NYMEX, but also due to changes in light-heavy crude oil supply and product demand-mix applicable to specific refining regions.

This Partnership's revenue, income, cash available for distribution to partners and reserves depend substantially on the prices it receives for its production. These prices have been volatile in the past for reasons beyond this Partnership's control and this volatility is expected to continue.

Number of total and full-time employees. This Partnership has no employees and relies on the Managing General Partner to manage this Partnership's business. PDC's officers, directors and employees receive direct remuneration, compensation or reimbursement solely from PDC, and not this 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 this Partnership to the Managing General Partner.

ITEM 1A. RISK FACTORS

Not applicable.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Information regarding this Partnership's wells, production, proved reserves and properties are included in Item 1, Business.

ITEM 3. LEGAL PROCEEDINGS

This Partnership is not currently subject to any material pending legal proceedings. See Note 7, Commitments and Contingencies, to the accompanying financial statements included elsewhere in this report for additional information related to litigation.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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18

PART II

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

AND ISSUER PURCHASES OF EQUITY SECURITIES

As of December 31, 2013, this Partnership had 1,783 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 this Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. Through December 31, 2013, the Managing General Partner has repurchased 41.3 units of Partnership interests from Investor Partners.

Market. There is no public market for this Partnership's 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 Agreement. This 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 this Partnership. Consequently, an individual investor partner must be able to bear the economic risk of investing in this 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 this 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 this Partnership. The Managing General Partner considers cash available for distributions to be this Partnership's net cash flows from operating activities, less any net cash used in capital activities.

PDC cannot presently predict amounts of future cash distributions, if any, from this Partnership. However, PDC expressly conditions any and all future cash distributions upon this Partnership having sufficient cash available for distribution. Sufficient cash available for distribution is defined generally as cash generated by this Partnership in excess of the amount the Managing General Partner determines is necessary or appropriate to provide for the conduct of this Partnership's business, comply with applicable law, comply with any other agreements or provide for future distributions to unit holders. In this regard, PDC reviews the accounts of this 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 this 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 will be attained, cash distributions will equal or approximate cash distributions made to investor partners of prior drilling programs sponsored by PDC or any level of cash distributions can be maintained. Fully developing all of this Partnership's properties would require substantial capital expenditures. Because of the restrictions set forth in the Agreement on making assessments on limited partnership units, this Partnership would generally be unable to fund such capital expenditures without bank borrowing or retaining all or a substantial portion of this Partnership's cash flows. 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 this Partnership. These funds are held in this Partnership's bank account, which is included in this 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 arises, 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 decides 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 proportionate share. Depending upon the level of withholding and the results of operations, it is possible that investors could have taxable income from this

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Partnership without any corresponding distributions in future years. Certain events, such as a liquidation or merger or other acquisition of this Partnership, would result in cessation of all future cash payments. The exchange by a non-affiliated 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 this Partnership's Additional Development Plan see Item 1, Business - Operations - Drilling and Other Development Activities - Additional Development 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 the Additional Development Plan and of 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, 2013	$	20,863,568
For the year ended December 31, 2012	7,136,923
For the period from this Partnership's inception to December 31, 2013	110,375,541

The increase in distributions for the year ended December 31, 2013 as compared to 2012 was primarily due to the July 2013 distribution of the proceeds received for the Piceance Basin asset divestiture of $13.5 million, including $5.0 million and $8.5 million to the Managing General Partner and the Investor Partners, respectively.

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 flows generated by this Partnership's activities and the amounts available for distribution to this Partnership's Investor Partners will, therefore, decline in the absence of significant increases in the prices that this Partnership receives for its crude oil, natural gas and NGLs production, or significant increases in the production of crude oil, natural gas and NGLs from the successful additional development of these properties, if any. The funds necessary for any additional development would be withheld from this 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 this Partnership's Wattenberg Field wells see Item 1, Business−Operations - Drilling and Other Development Activities - Additional Development Plan. For more information concerning this 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 this Partnership to borrow funds on its behalf for Partnership activities, exclusive of funds for the payment of cash distributions. This Partnership may borrow needed funds from the Managing General Partner or from unaffiliated persons. On loans or advances made available to this 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 this 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. As this Partnership may have to pay interest on borrowed funds, the amount of Partnership funds available for distribution to the partners of this 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 this 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 this Partnership to be treated as a “publicly traded partnership” or result in the termination of this Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis.

The following table presents information about the Managing General Partner's limited partner unit repurchases during each of the three months ended December 31, 2013:

Period	Total Number of  Units Repurchased	Average Price Paid  Per Unit
October 1 - 31, 2013	—	$	—
November 1 - 30, 2013	1.00	5,320
December 1 - 31, 2013	1.00	4,655
Total	2.00	$	4,988

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

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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 Annual Report on Form 10-K, should be read in conjunction with this Partnership's accompanying financial statements and related notes to the financial statements included elsewhere in this report. Further, this Partnership encourages the reader to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report.

Partnership Overview

Rockies Region 2007 Limited Partnership engages in the development, production and sale of crude oil, natural gas and NGLs. This Partnership began crude oil and natural gas operations in August 2007 and currently operates 75 gross (73.9 net) productive wells located in the Wattenberg Field of Colorado. The Managing General Partner markets this Partnership's crude oil, natural gas and NGLs production to midstream marketers. Crude oil, natural gas and NGLs are sold primarily under market-sensitive contracts in which the price varies as a result of market forces. PDC does not charge a separate fee for the marketing of the crude oil, natural gas and NGLs because these services are covered by the monthly well operating charge. Seasonal factors, such as effects of weather on prices received, costs incurred and availability of PDC or third-party owned pipeline capacity, and other factors such as high pressures in the gathering system whether caused by heat or third-party facilities issues, may impact this Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

PDC, on behalf of this Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts and/or to utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. In accordance with the D&O Agreement, the Managing General Partner may enter into derivative arrangements on behalf of this Partnership. The Managing General Partner has not entered into such arrangements on behalf of this Partnership in the last few years and does not anticipate entering into additional commodity based derivative instruments on behalf of this Partnership; however, this could change in the future.

Crude Oil and Natural Gas Properties Divestiture. In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement with certain affiliates of Caerus, pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. This divestiture was completed in June 2013 with total consideration to this Partnership of $13.5 million. The sale resulted in a loss on divestiture of assets of approximately $0.5 million. In July 2013, this Partnership distributed the proceeds of the sale to its partners on a pro rata basis. Following the sale to Caerus, this Partnership does not have continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the statement of operations for all periods presented.

Partnership Operating Results Overview

Crude oil, natural gas and NGLs sales from continuing operations decreased 3% for the year ended December 31, 2013 compared to the year ended December 31,2012, as a decrease in sales volumes from continuing operations of 5% was partially offset by a 2% increase in the average selling price year over year. The average selling price per Boe, excluding the impact of net settlements on derivatives, was $52.20 for the current year compared to $51.09 for 2012. Net settlements from all natural gas derivatives, including this Partnership's derivative positions liquidated or sold to Caerus in late June prior to settlement, contributed approximately $1.3 million to total revenues for the year ended December 31, 2013, compared to approximately $3.5 million from net settlements of natural gas derivatives for the year ended December 31,2012.

In December 2012, this Partnership recognized an impairment charge of approximately $2.2 million associated with its Piceance Basin proved oil and natural gas properties. See Note 10, Impairment of Capitalized Costs, to this Partnership's financial statements for additional details of this Partnership's proved property impairment.

Results of Operations

Summary Operating Results

The following table presents selected information regarding this Partnership’s results from continuing operations:

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	Twelve months ended December 31,
	2013		2012		Change
Number of gross producing wells (end of period)	75		75		—
Production(1)
Crude oil (Bbl)	51,256		57,783		(11	)%
Natural gas (Mcf)	217,750		221,754		(2	)%
NGLs (Bbl)	21,712		20,830		4	%
Crude oil equivalent (Boe)(2)	109,260		115,572		(5	)%
Average Boe per day	299		316		(5	)%
Crude oil, natural gas and NGLs sales
Crude oil	$	4,648,840	$	4,986,162	(7	)%
Natural gas	688,604		541,638		27	%
NGLs	365,499		376,916		(3	)%
Total crude oil, natural gas and NGLs sales	$	5,702,943	$	5,904,716	(3	)%
Net settlements on derivatives
Natural gas	$	1,275,544	$	3,462,935	(63	)%
Average selling price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	90.70	$	86.29	5	%
Natural gas (per Mcf)	3.16		2.44		30	%
NGLs (Bbl)	16.83		18.09		(7	)%
Crude oil equivalent (per Boe)	52.20		51.09		2	%
Average cost per Boe
Crude oil, natural gas and NGLs production cost(3)	$	12.77	$	11.29	13	%
Depreciation, depletion and amortization	28.57		29.99		(5	)%
Operating costs and expenses
Direct costs - general and administrative	$	209,500	$	200,972	4	%
Depreciation, depletion and amortization	3,121,340		3,466,521		(10	)%
Cash distributions	$	20,863,568	$	7,136,923	*

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

Amounts may not recalculate due to rounding.

_______________

⁽¹⁾ Production is net and determined by multiplying the gross production volume of properties in which this Partnership has an interest by the average percentage of the leasehold or other property interest this Partnership owns. For total production volume, including discontinued operations. See Part I, Item 1, Operations - Production, Sales, and Lifting Costs - By Field included in this report.

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

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

Crude Oil, Natural Gas and NGLs Sales

Changes in Crude Oil, Natural Gas and NGLs Sales Volumes. For 2013 compared to 2012, crude oil, natural gas and NGLs production, on an energy equivalency-basis, decreased 5% due to normal production declines for this stage in the wells' production life cycle. These declines were offset in part by increased production from wells refractured or recompleted, in accordance with the Additional Development Plan, and turned-in-line in the second half of 2012.

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Changes in Crude Oil Sales. The approximate $337,000, or 7%, decrease in crude oil sales for 2013 as compared to 2012 was primarily due to a production volume decrease of 11%, partially offset by an increased average selling price of 5% per Bbl. The average selling price per Bbl was $90.70 for the current annual period compared to $86.29 for the same period a year ago.

Changes in Natural Gas Sales. The approximate $147,000, or 27%, increase in natural gas sales for 2013 as compared to 2012 was due to a higher average selling price per Mcf of 30%, partially offset by a production volume decrease of 2%. The average selling price per Mcf was $3.16 for the current annual period compared to $2.44 for the same period a year ago.

Changes in NGLs Sales. The approximate $11,000, or 3%, decrease in NGLs sales for 2013 as compared to 2012 was due to a decrease in the average selling price of 7% per Bbl, partially offset by a production volume increase of 4%. The average selling price per Bbl was $16.83 for the current annual period compared to $18.09 for the same period a year ago.

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

Crude oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and international politics. In the Wattenberg Field, crude oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials. Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price this Partnership receives for its natural gas produced in the Wattenberg Field is based on CIG prices, adjusted for differentials. This Partnership's price for NGLs produced in the Wattenberg Field is mainly based on prices from the Conway hub in Kansas where this production is marketed.

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

Commodity Price Risk Management

This Partnership used various derivative instruments to manage fluctuations in natural gas prices. In June 2013, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated or sold to Caerus. Accordingly, as of December 31, 2013, this Partnership did not have any derivative instruments in place for its future production. Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production.

Prior to June 30, 2013, this Partnership had in place collars, fixed-price swaps and/or basis swaps on a portion of this Partnership's estimated natural gas production. This Partnership sold its natural gas at similar prices to the indices inherent in this Partnership's derivative instruments. As a result, for the volumes underlying this Partnership's derivative positions, this Partnership's settlement price related to its collars was no less than the floor and no more than the ceiling and, for this Partnership's commodity swaps, this Partnership's settlement price was the fixed price related to its swaps.

Commodity price risk management includes cash settlements upon maturity of this Partnership's derivative instruments and the change in fair value of unsettled derivatives related to this Partnership's natural gas production. See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to this Partnership's financial statements included elsewhere in this report for additional details of this Partnership's derivative financial instruments.

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The following table presents the net settlements and net change in fair value of unsettled derivatives included in commodity price risk management gain (loss), net:

	Year ended December 31,
	2013			2012
Commodity price risk management gain (loss), net:
Net settlements	$	1,275,544		$	3,462,935
Net change in fair value of unsettled derivatives	(1,693,233		)	(2,384,355		)
Total commodity price risk management gain (loss), net	$	(417,689	)	$	1,078,580

This Partnership had no crude oil, natural gas or NGLs derivative activity subsequent to June 30, 2013 as all open positions were either sold or liquidated prior to June 30, 2013. Unless this Partnership enters into derivative arrangements in the future, its income statement will not reflect activity in commodity price risk management. Net settlements of approximately $1.3 million for the year ended December 31, 2013 were primarily the result of lower natural gas index prices at maturity of this Partnership’s derivative instruments compared to the respective strike prices. Positive settlements on natural gas, exclusive of basis swaps, were approximately $2.5 million. Positive settlements were offset in part by negative settlements of approximately $1.2 million on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average prices was narrower than the strike price of this Partnership's basis swaps. The net change in fair value of unsettled derivatives in 2013 represents a net asset reduction in the beginning-of-period fair value of derivative instruments that settled during the period. The corresponding impact of settlement of these instruments is included in net settlements for the period as discussed above.

Net settlements of approximately $3.5 million for the year ended December 31, 2012 were primarily the result of lower natural gas index prices at maturity of this Partnership’s derivative instruments compared to the respective strike prices. Positive settlements on natural gas, exclusive of basis swaps, were approximately $5.8 million. Positive settlements were offset in part by negative settlements of approximately $2.3 million on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average prices was narrower than the strike price of this Partnership's basis swaps. The net change in fair value of unsettled derivatives in 2012 includes an approximately $2.9 million net asset reduction in the beginning-of-period fair value of derivative instruments that settled during the period. This reduction was offset in part by an approximately $0.5 million increase in the fair value of unsettled derivatives during the period, primarily related to the downward shift in the natural gas forward curve.

Crude Oil, Natural Gas and NGLs Production Costs

Crude oil, natural gas and NGLs 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 per unit production cost 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 this Partnership successfully executes this Partnership's Additional Development Plan for the Wattenberg Field wells.

Generally, crude oil, natural gas and NGLs production costs vary with changes in total crude oil, natural gas and NGLs 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 crude oil, natural gas and NGLs sales. 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 crude oil, natural gas and NGLs production expenses. Crude oil, natural gas and NGLs production costs for continuing operations for the year ended December 31, 2013 increased by approximately $91,000 compared to 2012. The increase in crude oil, natural gas and NGLs production costs was due to higher service rig and well swabbing costs in 2013 compared to 2012.

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Depreciation, Depletion and Amortization

Crude oil and natural gas properties. Depreciation, depletion and amortization ("DD&A") expense related to crude oil and natural gas 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. DD&A expense for continuing operations decreased approximately $345,000 for the year ended December 31, 2013 compared to the same period in 2012 due to lower production volumes of 5% in 2013 and a decreased DD&A expense rate in 2013. The DD&A expense rate per Boe decreased to $28.57 for the 2013annual period compared to $29.99 during the same period in 2012 primarily due to the effect of the impairment recorded on the Wattenberg Field assets during 2012.

Impairment of Crude Oil and Natural Gas Properties

In December 2012, this Partnership recognized an impairment charge of $2.2 million associated with its Piceance Basin proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on estimated future cash flows from unrelated third-party bids, a Level 3 input.

See Note 10, Impairment of Capitalized Costs, to this Partnership's financial statements included elsewhere in this report for additional details of this Partnership's proved property impairment.

Discontinued Operations

In February 2013, the Managing General Partner entered into a purchase and sale agreement with Caerus, pursuant to which this Partnership agreed to sell to Caerus its Piceance Basin assets and certain derivatives. In June 2013, this divestiture was completed with total consideration to this Partnership of $13.5 million. The sale resulted in a loss on divestiture of assets of $0.5 million. In July 2013, this Partnership distributed the proceeds from the divestiture of $13.5 million to the partners. The effective date of the transaction was January 1, 2013. Following the sale to Caerus, this Partnership does not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin assets. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the statement of operations for all periods presented. See Note 11, Divestitures and Discontinued Operations, to the accompanying financial statements included elsewhere in this report for additional information regarding the sale.

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

	Year Ended December 31,
Discontinued Operations	2013	2012
Production
Crude oil (Bbl)	1,513	2,726
Natural gas (Mcf)	516,160	1,231,342
Crude oil equivalent (Boe)	87,540	207,949

Financial Condition, Liquidity and Capital Resources

This Partnership's primary source of liquidity has been cash flows from operating activities. This source of cash has been primarily used to fund this Partnership's operating costs, direct costs-general and administrative and monthly distributions to the Investor Partners and the Managing General Partner. Additionally, during the year ended December 31, 2012, $3,061,000 was paid to the Managing General Partner to cover the cost of initiating both recompletions and refracturing of certain Partnership wells and for major repair projects.

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Fluctuations in this Partnership's operating cash flows are substantially driven by changes in commodity prices, sales volumes and, historically, net settlements of derivatives from this Partnership's commodity contracts. Commodity prices have historically been volatile and, through June 30, 2013, the Managing General Partner managed this volatility through the use of derivatives. Therefore, historically, the primary source of cash flows from operations became the net activity between crude oil, natural gas and NGLs sales and the net settlements upon maturity of this Partnership's derivatives. This Partnership has no crude oil, natural gas or NGLs derivative positions at December 31, 2013 as all open positions were either sold to Caerus pursuant to the Piceance Basin asset divestiture or liquidated prior to June 30, 2013. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on this Partnership's revenues through December 31, 2013and Partnership Overview regarding the Managing General Partner's current plans regarding derivatives.

This Partnership's future operations are expected to be conducted with available funds and revenues generated from crude oil, natural gas and NGLs production activities. Crude oil, natural gas and NGLs production from existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, this Partnership anticipates a lower annual level of crude oil, natural gas and NGLs production and, in the absence of significant price increases or additional reserve development, lower revenues. This Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances, decreased production would have a material adverse impact on this Partnership's operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through 2014 and beyond.

Although the D&O Agreement permits this Partnership to borrow funds on its behalf for Partnership activities, the Managing General Partner does not anticipate electing to fund any portion of this Partnership's refracturing and recompletion activities, which began in 2012, through borrowings. Partnership borrowings, should any occur, will be non-recourse to the Investor Partners. Accordingly, this Partnership, rather than the Investor Partners, will be responsible for repaying any amounts borrowed.

Working Capital

At December 31, 2013, this Partnership had working capital of $0.9 million, compared to working capital of $4.6 million at December 31, 2012. The decrease of $3.7 million was primarily due to the following changes:

• accounts receivable decreased $1.0 million between December 31, 2013 and December 31, 2012;

• net settlements of derivatives receivable decreased by $2.8 million between December 31, 2013 and December 31, 2012; and

• accounts payable decreased by $0.1 million between December 31, 2013 and December 31, 2012.

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

Cash Flows

Operating Activities

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

Net cash flows from operating activities were approximately $7.4 million for the year ended December 31, 2013 compared to approximately $8.2 million in 2012. The decrease of approximately $0.8 million in cash from operating activities was due primarily to the following:

• a decrease in commodity price risk management realized gain receipts of approximately $1.7 million;

• an increase in crude oil, natural gas and NGLs sales receipts of $0.5 million; and

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

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Investing Activities

Cash flows from investing activities primarily consist of proceeds received from the disposition of crude oil and natural gas properties, offset by investments in equipment and services. During the twelve months ended December 31, 2013, proceeds from the disposition of crude oil and natural gas properties were approximately $13.5 million. From time to time, this Partnership invests in equipment which supports treatment, delivery and measurement of crude oil, natural gas and NGLs or environmental protection. There were no investments for this Partnership in 2013. Substantially all of the $3.2 million investment in 2012 is attributable to activities pursuant to the Additional Development Plan.

Financing Activities

This Partnership initiated monthly cash distributions to investors in May 2008 and has distributed $110.4 million through December 31, 2013. The table below presents cash distributions to this Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to the Managing General Partner for its 37% general partner interest in this Partnership and Investor Partner distributions include amounts distributed to Investor Partners for their 63% ownership share in this Partnership, as well as amounts distributed to the Managing General Partner for limited partnership units repurchased.

Cash Distributions
Year ended December 31,	Managing General Partner		Investor Partners		Total
2013	$	7,719,520	$	13,144,048	$	20,863,568
2012	2,640,661		4,496,262		7,136,923

The increase in distributions for the year ended December 31, 2013 as compared to 2012 was primarily due to the July 2013 distribution of the proceeds received for the Piceance Basin asset divestiture of $13.5 million, including $5.0 million and $8.5 million to the Managing General Partner and the Investor Partners, respectively. For additional information, see Recent Developments − Additional Development Plan above.

Off-Balance Sheet Arrangements

As of December 31, 2013, this Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on this Partnership's financial condition, results of operations, liquidity, capital expenditures or capital resources.

Commitments and Contingencies

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

Recent Accounting Standards

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

28

Critical Accounting Policies

The Managing General Partner has identified the following policies as critical to business operations and the understanding of the results of operations of this Partnership. The following is not a comprehensive list of all of this Partnership's accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States of America, with no need for management's judgment in their application. There are also areas in which management's judgment in selecting available alternatives would not produce a materially different result. However, certain of this Partnership's accounting policies are particularly important to the portrayal of this 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 an 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, to the financial statements included elsewhere in this report.

Crude Oil, Natural Gas and NGLs Properties

This Partnership accounts for its crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties and development 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 independent petroleum engineers to prepare reserve and economic evaluations of this Partnership's properties on a well-by-well basis as of December 31. Proved developed reserves are those crude oil, natural gas and NGLs quantities expected to be recovered from currently producing zones under the continuation of present operating methods. This Partnership's reserves are adjusted for divestitures during the year as needed. The process of estimating and evaluating crude oil, natural gas and NGLs 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 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. 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 this Partnership's DD&A expense, a change in this Partnership's estimated reserves could have an effect on its net income.

This Partnership assesses its crude oil and natural gas properties for possible impairment upon a triggering event by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. Any impairment in value is charged to impairment of crude oil and natural gas properties. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to this 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 this Partnership's crude oil and natural gas properties. Although this 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.

Crude Oil, Natural Gas and NGLs Sales Revenue Recognition

Crude oil, natural gas and NGLs 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. This 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 this Partnership's sales volumes based on the Managing General Partner's measured volume readings. The Managing General Partner then adjusts this Partnership's crude oil, natural gas and NGLs sales in subsequent periods based on the data received from this Partnership's purchasers that reflects actual volumes and prices received. This 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.

29

This Partnership’s crude oil, natural gas and NGLs sales are concentrated with a few major customers. This concentrates the significance of credit risk exposure. To date, this Partnership has had no material counterparty default losses. See Note 5, Concentration of Risk, to our financial statements included elsewhere in this report.

Asset Retirement Obligations

Asset retirement obligations are accounted for by recording the fair value of well plugging and abandonment obligations when incurred, which is at the time the well is spud. Upon initial recognition of an asset retirement obligation carrying amount of the long-lived asset is increased by the same amount as the liability. Over time, the liabilities are accreted for the change in present value. The initial capitalized costs, net of salvage value, 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 changes in retirement costs or the estimated timing of settling asset retirement obligations.

Fair Value of Financial Instruments

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

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

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

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

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

The Managing General Partner validated its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While the Managing General Partner used 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 believed its valuation method was 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 have resulted in a different estimate of fair value.

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies - Recent Accounting Standards, to this Partnership's financial statements included elsewhere in this report.

30

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

31

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Rockies Region 2007 Limited Partnership

Index to Financial Statements

Report of Independent Registered Public Accounting Firm	33
Balance Sheets - December 31, 2013 and 2012	34
Statements of Operations - For the Years Ended December 31, 2013 and 2012	35
Statements of Partners' Equity - For the Years Ended December 31, 2013 and 2012	36
Statements of Cash Flows - For the Years Ended December 31, 2013 and 2012	37
Notes to Financial Statements	38
Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited	50

32

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, 2013 and 2012, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2013 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 the Partnership's Managing General Partner, PDC Energy, Inc., and its subsidiaries.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

April 4, 2014

33

Rockies Region 2007 Limited Partnership

Balance Sheets

	December 31, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	570,376		$	570,376
Accounts receivable	378,940			865,944
Crude oil inventory	55,308			42,939
Due from Managing General Partner-derivatives	—			4,409,574
Due from Managing General Partner-other, net	—			800,598
Total current assets	1,004,624			6,689,431
Crude oil and natural gas properties, successful efforts method, at cost	55,748,749			79,601,649
Less: Accumulated depreciation, depletion and amortization	(31,819,541		)	(38,868,788		)
Crude oil and natural gas properties, net	23,929,208			40,732,861
Other assets	89,630			46,711
Total Assets	$	25,023,462		$	47,469,003
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	33,041		$	90,570
Due to Managing General Partner-derivatives	—			2,004,594
Due to Managing General Partner-other, net	119,994			—
Total current liabilities	153,035			2,095,164
Asset retirement obligations	935,813			1,110,093
Total liabilities	1,088,848			3,205,257
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	3,661,859			11,183,638
Limited Partners - 4,470 units issued and outstanding	20,272,755			33,080,108
Total Partners' equity	23,934,614			44,263,746
Total Liabilities and Partners' Equity	$	25,023,462		$	47,469,003

See accompanying notes to financial statements.

34

Rockies Region 2007 Limited Partnership

Statements of Operations

	Year ended December 31,
	2013			2012
Revenues:
Crude oil, natural gas and NGLs sales	$	5,702,943		$	5,904,716
Commodity price risk management gain (loss), net	(417,689		)	1,078,580
Total revenues	5,285,254			6,983,296
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	1,395,391			1,304,676
Direct costs - general and administrative	209,500			200,972
Depreciation, depletion and amortization	3,121,340			3,466,521
Accretion of asset retirement obligations	68,266			63,165
Total operating costs and expenses	4,794,497			5,035,334
Income from continuing operations	490,757			1,947,962
Income (loss) from discontinued operations	43,679			(3,327,789		)
Net income (loss)	$	534,436		$	(1,379,827	)
Income from continuing operations	$	490,757		$	1,947,962
Less: Managing General Partner interest in net income from continuing operations	181,580			720,746
Net income from continuing operations allocated to Investor Partners	$	309,177		$	1,227,216
Income (loss) from discontinued operations	$	43,679		$	(3,327,789	)
Less: Managing General Partner interest in net income (loss) from discontinued operations	16,161			(1,231,282		)
Income (loss) from discontinued operations allocated to Investor Partners	$	27,518		$	(2,096,507	)
Net income (loss) per Investor Partner unit
Continuing operations	$	69		$	275
Discontinued operations	6			(469		)
Net loss per Investor Partner unit	$	75		$	(194	)
Investor Partner units outstanding	4,470			4,470

See accompanying notes to financial statements.

35

Rockies Region 2007 Limited Partnership

Statements of Partners' Equity

For the Years Ended December 31, 2013 and 2012

				Managing
	Investor			General
	Partners			Partner			Total
Balance, December 31, 2011	$	38,445,661		$	14,334,835		$	52,780,496
Distributions to partners	(4,496,262		)	(2,640,661		)	(7,136,923		)
Net loss	(869,291		)	(510,536		)	(1,379,827		)
Balance, December 31, 2012	33,080,108			11,183,638			44,263,746
Distributions to partners	(13,144,048		)	(7,719,520		)	(20,863,568		)
Net income	336,695			197,741			534,436
Balance, December 31, 2013	$	20,272,755		$	3,661,859		$	23,934,614

See accompanying notes to financial statements.

36

Rockies Region 2007 Limited Partnership

Statements of Cash Flows

	Year ended December 31,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	534,436		$	(1,379,827	)
Adjustments to net income (loss) to reconcile to net cash    from operating activities:
Depreciation, depletion and amortization	3,276,550			5,439,026
Accretion of asset retirement obligations	75,144			78,907
Net change in fair value of unsettled derivatives	1,693,233			2,384,355
Loss on sale of crude oil and natural gas properties	495,574			—
Impairment of crude oil and natural gas properties	—			2,191,002
Changes in assets and liabilities:
Accounts receivable	487,004			(97,994		)
Crude oil inventory	(17,283		)	4,308
Other assets	(42,919		)	(46,711		)
Accounts payable and accrued expenses	(57,529		)	(4,959		)
Due to Managing General Partner-other, net	130,241			—
Due from Managing General Partner-other, net	800,598			(389,027		)
Net cash from operating activities	7,375,049			8,179,080
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	—			(3,162,158		)
Proceeds from the sale of crude oil and natural gas properties	13,488,519			—
Net cash from investing activities	13,488,519			(3,162,158		)
Cash flows from financing activities:
Distributions to Partners	(20,863,568		)	(7,136,923		)
Net cash from financing activities	(20,863,568		)	(7,136,923		)
Net change in cash and cash equivalents	—			(2,120,001		)
Cash and cash equivalents, beginning of period	570,376			2,690,377
Cash and cash equivalents, end of period	$	570,376		$	570,376

See accompanying notes to financial statements.

37

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

NOTE 1 - GENERAL

Rockies Region 2007 Limited Partnership was organized in 2007 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 crude oil and natural gas properties. Business operations commenced upon closing of an offering for the private placement of Partnership units. Upon funding, this Partnership entered into a D&O Agreement with the Managing General Partner which authorizes PDC to conduct and manage this Partnership's business. In accordance with the terms of the Agreement, the Managing General Partner is authorized to manage all activities of this Partnership and initiates and completes substantially all Partnership transactions.

As of December 31, 2013, there were 1,783 Investor Partners in this Partnership. PDC is the designated Managing General Partner of this Partnership and owns a 37% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 63% to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership, and 37% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. For more information about the Managing General Partner's limited partner unit repurchase program, see Note 8, Partners' Equity and Cash Distributions. Through December 31, 2013, the Managing General Partner had repurchased 41.3 units of Partnership interests from the Investor Partners at an average price of $4,269 per unit. As of December 31, 2013, the Managing General Partner owned 37.6% of this Partnership.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. These reclassifications had no impact on previously reported cash flows, net income, earnings per investor partner unit or partners' equity.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management's Estimates

The preparation of this Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires this Partnership to make estimates and assumptions that affect the amounts reported in this 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, NGLs and crude oil sales revenue, proved reserves, future cash flows from crude oil, natural gas and NGLs 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 this Partnership.

Cash and Cash Equivalents. This Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. This Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. The balance in this Partnership's account is insured by Federal Deposit Insurance Corporation, up to $250,000. This Partnership has not experienced losses in any such accounts to date and limits this 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. This Partnership's accounts receivable are from purchasers of crude oil, natural gas and NGLs. This Partnership sells substantially all of its crude oil, natural gas and NGLs to customers who purchase crude oil, natural gas and NGLs from other partnerships managed by this 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 for doubtful accounts was deemed necessary at December 31, 2013 or 2012.

38

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 this 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, this 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. This Partnership is exposed to the effect of market fluctuations in the prices of crude oil and natural gas. The Managing General Partner previously employed established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production. The Managing General Partner's policy prohibits the use of crude oil and natural gas derivative instruments for speculative purposes.

All derivative assets and liabilities were recorded on the balance sheets at fair value. PDC, as Managing General Partner, elected not to designate any of this Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of this Partnership's derivative instruments were recorded in this Partnership's statements of operations and this Partnership's net income was subject to greater volatility than it would have been if this Partnership's derivative instruments had qualified for hedge accounting. The net settlements and the net change in fair value of unsettled derivatives are recorded in the line captioned, “Commodity price risk management gain, net.” As positions designated to this Partnership settled, positive and negative settlements were netted for distribution. Positive settlements were paid to this Partnership and negative settlements were deducted from this Partnership's cash distributions generated from production. This Partnership bore its proportionate share of counterparty risk. As of December 31, 2013, this Partnership had no outstanding derivative instruments.

The validation of the derivative instrument's fair value was performed by the Managing General Partner. While the Managing General Partner used common industry practices to develop this Partnership's valuation techniques, changes in this Partnership's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values. See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, for a discussion of this Partnership's derivative fair value measurements as of December 31, 2012.

Crude Oil and Natural Gas Properties. This Partnership accounts for its crude oil and natural gas 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. This Partnership calculates quarterly DD&A expense by using estimated prior period-end reserves as the denominator, with the exception of this Partnership's fourth quarter where this Partnership uses the year-end reserve estimate adjusted to add back fourth quarter 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 Crude Oil, Natural Gas and NGLs Information - Unaudited,Net Proved Reserves, included at the end of these financial statements and accompanying notes elsewhere in this report for additional information regarding this Partnership's reserve reporting. In accordance with the Agreement, all capital contributed to this Partnership, after deducting syndication costs and a one-time management fee, was used solely for the drilling of crude oil and natural gas wells. This Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of crude oil, natural gas and NGLs 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 this Partnership's properties on a well-by-well basis as of December 31. Additionally, this Partnership adjusts reserves for major well rework or abandonment during the year, as needed. The process of estimating and evaluating crude oil, natural gas and NGLs 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 this 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

39

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

estimates over time. Because estimates of reserves significantly affect this Partnership's DD&A expense, a change in this Partnership's estimated reserves could have an effect on this Partnership's net income or loss.

Proved Property Impairment. Upon a triggering event, this Partnership assesses its producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, 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 crude oil and natural gas. Certain events, including but not limited to, downward revisions in estimates to this 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 this Partnership's proved crude oil and natural gas 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 and is measured by the amount by which the net capitalized costs exceed their fair value. Impairment charges are included in the statement of operations line item impairment of crude oil and natural gas properties, with a corresponding reduction to crude oil and natural gas properties and accumulated depreciation, depletion and amortization line items on the balance sheet.

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 this Partnership produces crude oil, natural gas and NGLs. This Partnership's share of these taxes recorded in the line crude oil, natural gas and NGLs production costs on this Partnership's statements of operations. This Partnership's production taxes payable are included in the caption accounts payable and accrued expenses on this Partnership's balance sheets.

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

Asset Retirement Obligations.This 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 spud. Upon initial recognition of an asset retirement obligation, this 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, net of salvage value, 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 changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 6, Asset Retirement Obligations, for a reconciliation of the changes in this Partnership's asset retirement obligation.

Revenue Recognition. Crude oil, natural gas and NGLs 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. This Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of this Partnership's sales pursuant to which the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells this 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 this Partnership's purchasers and reflected in the wellhead price. The majority of this Partnership's natural gas and NGLs is sold by the Managing General Partner on a long-term basis, primarily over 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 and the quality of the natural gas.

Recent Accounting Standards

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

40

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments

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

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

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

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

Derivative instruments that were due to mature subsequent to June 30, 2013 were either liquidated or sold to Caerus during the quarter ended June 30, 2013. See Note 11, Divestitures and Discontinued Operations, for additional information regarding transactions with Caerus. Accordingly, as of December 31, 2013, this Partnership did not have any derivative instruments in place for its future production. When applicable, the Managing General Partner measured the fair value of this Partnership's derivative instruments based on a pricing model that utilized market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas forward curve, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validated its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While the Managing General Partner used common industry practices to develop its valuation techniques, and believed this Partnership's valuation method was appropriate and consistent with those used by other market participants, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values.

41

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

This Partnership's fixed-price swaps and basis swaps as of December 31, 2012 were included in Level 2. The following table presents this Partnership's derivative assets and liabilities that had been measured at fair value on a recurring basis:

	Balance Sheet	December 31, 2012
	Line Item	Level 2
Assets:
Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	4,409,574
Total assets		4,409,574
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	2,004,594
Total liabilities		2,004,594
Net asset		$	2,404,980

Non-Derivative Financial Assets and Liabilities

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

See Note 2, Summary of Significant Accounting Policies, Crude Oil and Natural Gas Properties and Asset Retirement Obligations, for a discussion of how this Partnership determined fair value for these assets and liabilities.

NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS

This Partnership's results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. Prior to June 30, 2013, to manage a portion of this Partnership's exposure to price volatility from producing crude oil and natural gas, the Managing General Partner utilized an economic hedging strategy for this Partnership's crude oil and natural gas sales in which PDC, as Managing General Partner, entered into derivative contracts on behalf of this Partnership to protect against price declines in future periods. While the Managing General Partner structured these derivatives to reduce this Partnership's exposure to changes in price associated with the derivative commodities, they also limited the benefit this Partnership might otherwise have received from price increases in the physical market. Partnership policy prohibited the use of crude oil and natural gas derivative instruments for speculative purposes. In June 2013, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated or sold to Caerus. Accordingly, as of December 31, 2013, this Partnership did not have any derivative instruments in place for its future production. Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production.

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

	Year ended December 31,
Statement of operations line item:	2013			2012
Commodity price risk management gain (loss), net
Net settlements	$	1,275,544		$	3,462,935
Net change in fair value of unsettled derivatives	(1,693,233		)	(2,384,355		)
Total commodity price risk management gain (loss), net	$	(417,689	)	$	1,078,580

42

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 5 - CONCENTRATION OF RISK

Accounts Receivable. This Partnership's accounts receivable are from purchasers of crude oil, natural gas and NGLs production. This Partnership sells substantially all of its crude oil, natural gas and NGLs to customers who purchase crude oil, natural gas and NGLs from other partnerships managed by this Partnership's Managing General Partner. Inherent to this Partnership's industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This industry concentration has the potential to impact this Partnership's overall exposure to credit risk in that its customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions.

As of December 31, 2013 and 2012, this 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 this 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 this Partnership's Managing General Partner, have experienced significant losses from uncollectible accounts receivable. This Partnership did not incur any losses on accounts receivable for the years ended December 31, 2013 and 2012. As of December 31, 2013, this Partnership had two customers representing 10% or more of the accounts receivable balance: Suncor Energy Marketing, Inc. and DCP Midstream, LP represented 76% and 22%, respectively.

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

	Year ended December 31,
Major Customer	2013	2012
Suncor Energy Marketing, Inc.	82%	84%
DCP Midstream, LP	18%	16%

NOTE 6 - ASSET RETIREMENT OBLIGATIONS

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

	Year ended December 31,
	2013			2012
Balance at beginning of period	$	1,110,093		$	1,031,186
Obligations discharged with divestiture of properties(1)	(249,424		)	—
Accretion expense	75,144			78,907
Balance at end of period	$	935,813		$	1,110,093

(1) This Partnership's asset retirement obligations relative to Piceance Basin assets were discharged with the sale of these assets during the year ended December 31, 2013. See Note 11, Divestiture and Discontinued Operations, for further information regarding the divestiture of the Piceance Basin assets.

43

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 7 - COMMITMENTS AND CONTINGENCIES

Legal Proceedings

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

Environmental

Due to the nature of the oil and gas industry, this Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in this Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews. Liabilities for environmental remediation efforts are included in line item captioned “Accounts payable and accrued expenses” on the balance sheets.

During the year ended December 31, 2013, as a result of the Managing General Partner's periodic review, no new environmental remediation projects were identified and this Partnership's expense for environmental remediation efforts was not significant. This Partnership had no liabilities for environmental remediation efforts as of December 31, 2013. This Partnership's environmental remediation liabilities were approximately $5,000 as of December 31, 2012.

The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2013 which have not been provided for or would otherwise have a material impact on this 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 or other potential sources of liability will not be discovered on this Partnership's properties.

Royalty Matters

During the year ended December 31, 2013, this Partnership recognized charges totaling approximately $326,000 related to royalty payment disputes with interest owners in the Piceance Basin. These charges were included in Direct costs - general and administrative expenses within discontinued operations. The settlement charges were allocated to this Partnership based upon historical revenue amounts and were paid during 2013, thereby settling all current and future obligations related to this matter.

44

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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 this Partnership. No publicmarket exists or will develop for the units. While units of this 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 described below.

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

			Managing
	Investor		General
	Partners		Partner
Partnership Revenue:
Crude oil, natural gas and NGLs 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:
Crude oil, natural gas and NGLs 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 this Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of this 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 this 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 this Partnership to be treated as a “publicly traded partnership” or result in the termination of this Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis.

45

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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,
	2013		2012
Cash distributions	$	20,863,568	$	7,136,923

Cash distributions increased in 2013 compared to 2012, primarily due to the July 2013 distribution of $13.5 million of the proceeds received for the Piceance Basin asset divestiture. See Note 11, Divestiture and Discontinued Operations, for additional details related to the divestiture of this Partnership's Piceance Basin assets.

NOTE 9 - TRANSACTIONS WITH MANAGING GENERAL PARTNER

The Managing General Partner transacts business on behalf of this Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received by the Managing General Partner on behalf of this Partnership are distributed to the partners, net of corresponding operating costs and other cash outflows incurred on behalf of this Partnership. The fair value of this Partnership's portion of open derivative instruments were recorded on the December 31, 2012 balance sheet under the captions “Due from Managing General Partner-derivatives” in the case of a positive fair value of unsettled derivatives and “Due to Managing General Partner-derivatives” in the case of a negative fair value of unsettled derivatives. As of December 31, 2013, this Partnership had no outstanding derivative instruments.

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

	December 31, 2013			December 31, 2012
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	306,014		$	871,548
Net settlements of derivatives	—			356,531
Other (1)	(426,008		)	(427,481		)
Total Due (to) from Managing General Partner-other, net	$	(119,994	)	$	800,598

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

Commencing with March 2012 well operations, the Managing General Partner withholds from monthly Partnership cash available for distributions amounts to be used to fund statutorily-mandated well plugging, abandonment and environmental site restoration expenditures. A Partnership well may be sold or plugged, reclaimed and abandoned, with consent of all non-operators, when depleted or an evaluation is made that the well has become uneconomical to produce. Per-well plugging fees withheld during 2013 and 2012 were $50 per well each month the well produced. The total amount withheld from Partnership's cash available for distributions for the purposes of funding future Partnership obligations is recorded on the balance sheets in the long-term asset line captioned "Other assets." PDC plans to discontinue withholding these funds in early 2014 and will refund all funds withheld to the Partnership.

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 for the years ended December 31, 2013 and 2012.

46

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

“Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the statements of operations for continuing operations or in Note 11, Divestiture and Discontinued Operations, for information on discontinued operations.    

	Year ended December 31,
	2013		2012
Well operations and maintenance (1)	$	1,660,093	$	2,260,438
Gathering, compression and processing fees (2)	119,017		339,542
Direct costs - general and administrative (3)	535,551		200,972
Refracturing and recompletion costs (4)	—		3,159,943
Cash distributions (5)	7,819,797		2,658,297

(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 this 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 this 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 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. 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 this 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 this Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between this 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 crude oil, natural gas and NGLs, such as:

• well tending, routine maintenance and adjustment;

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

• preparing production related reports to this 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; or

• 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 may enter into other transactions with this Partnership for services, supplies and equipment during the production phase of this 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.

47

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

(2) Under the Agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the natural gas produced by this 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, this 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, this Partnership pays the gathering fee charged by the third-party gathering the natural gas.

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

(4) Refracturing and recompletion costs relate to expenditures recorded pursuant to the Additional Development Plan.

(5) 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 the years ended December 31,2013 and 2012 include $100,277 and $17,636, respectively, related to equity cash distributions 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.

NOTE 10 - IMPAIRMENT OF CRUDE OIL AND NATURAL GAS PROPERTIES

In December 2012, this Partnership recognized an impairment charge of approximately $2.2 million associated with its Piceance Basin proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on estimated future cash flows from unrelated third-party bids, a Level 3 input. See Supplemental Crude Oil, Natural Gas and NGLs Information–Unaudited–Capitalized Costs and Costs Incurred in Crude Oil and Natural Gas Property Development Activities for additional information on impairment of crude oil and natural gas properties.

NOTE 11 - DIVESTITURE AND DISCONTINUED OPERATIONS

Piceance Basin. In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $13.5 million. The divestiture of this Partnership's Piceance Basin assets resulted in a decrease of crude oil and natural gas properties of $23.8 million and a decrease of accumulated depreciation, depletion and amortization of $10.3 million. The sale resulted in a loss on divestiture of assets of approximately $0.5 million, which is included in discontinued operations.

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture to the Managing General Partner and Investor Partners as follows:

	Amount
Distributed to:	(millions)
Managing General Partner	$	5.0
Investor Partners	8.5
Total	$	13.5

48

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

Following the sale, this Partnership does not have a significant continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the statement of operations for all periods presented.

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

	Year Ended December 31,
Statement of Operations - Discontinued Operations	2013		2012
Revenues:
Crude oil, natural gas and NGLs sales	$	1,771,961	$	2,356,542
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	744,569		1,505,082
Direct costs - general and administrative expense	326,051		—
Depreciation, depletion and amortization	155,210		1,972,505
Accretion of asset retirement obligations	6,878		15,742
Impairment of crude oil and natural gas properties	—		2,191,002
Loss on sale of crude oil and natural gas properties	495,574		—
Total operating costs and expenses	1,728,282		5,684,331
Income (loss) from discontinued operations	$	43,679	$	(3,327,789	)

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

49

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited

Net Proved Reserves

This Partnership utilized the services of an independent petroleum engineer, Ryder Scott, to estimate this Partnership's 2013 and 2012 crude oil, natural gas and NGLs 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. This 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 crude oil, natural gas and NGLs expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development. As of December 31, 2013 and 2012, there are no proved undeveloped reserves for this Partnership.

This Partnership's estimated proved developed non-producing reserves consist entirely of reserves attributable to the Wattenberg Field's additional development. These additional development activities, part of the Additional Development Plan, generally occur five to ten years after initial well drilling. Funds of $3.1 million, which were provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners, were utilized for payment of additional development activities during 2012. Additional Development Plan activities are suspended until pipeline capacity improves. 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 following table presents the prices used to estimate this Partnership's reserves, by commodity:

	Price Used to Estimate Reserves (1)
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2013	$	81.91	$	3.38	$	23.14
2012	87.51		2.31		23.07

(1) The prices used to estimate reserves have been prepared in accordance with the SEC. 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 this 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 this Partnership's commodity derivatives.

50

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited

The following table presents the changes in estimated quantities of this Partnership's reserves, all of which are located within the United States:

	Natural Gas		NGLs		Crude Oil and Condensate		Crude Oil Equivalent
	(MMcf)		(MBbl)		(MBbl)		(MBoe)
Proved Reserves:
Proved reserves, January 1, 2012	18,415		697		879		4,645
Revisions of previous estimates and reclassifications	(3,926	)	(81	)	34		(701	)
Production	(1,453	)	(21	)	(60	)	(323	)
Proved reserves, December 31, 2012 (1)	13,036		595		853		3,621
Revisions of previous estimates and reclassifications	(712	)	(74	)	(117	)	(310	)
Dispositions (1)	(6,874	)	—		(15	)	(1,161	)
Production	(734	)	(22	)	(53	)	(197	)
Proved reserves, December 31, 2013	4,716		499		668		1,953
Proved Developed Reserves, as of:
December 31, 2012	13,036		595		853		3,621
December 31, 2013	4,716		499		668		1,953

(1) Includes estimated reserve data related to this Partnership's Piceance Basin assets. In June 2013, this Partnership's Piceance Basin crude oil and natural gas properties were divested. See Note 11, Divestiture and Discontinued Operations, for additional information regarding this divestiture. As of December 31, 2012, total proved reserves related to this Partnership's Piceance Basin assets include 7,390 MMcf of natural gas and 17 MBbl of crude oil, for an aggregate of 1,249 MBoe of crude oil equivalent.

2013 Activity. As of December 31, 2013, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 310 MBoe. The revision includes downward revisions to previous estimates of 712 MMcf of natural gas, 74 MBbl of NGLs and 117 MBbl of crude oil. The downward revisions were the result of lower pricing, reduced asset performance and a reduction in proved non-producing reserves. There was a significant increase to the differential to NYMEX. A portion of non-producing reserves were reclassified from proved to probable due to not being economically producible. The outcome of these three items significantly decreased estimated reserves. The divestiture of this Partnership's Piceance Basin assets resulted in the disposition of reserves comprised of 6,874 MMcf of natural gas and 15 MBbl of crude oil. There were no proved undeveloped reserves developed in 2013. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2013.

2012 Activity. As of December 31, 2012, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 701 MBoe. The revision includes downward revisions to previous estimates of 3,926 MMcf of natural gas and 81 MBbls of NGLs, partially offset by an upward revision of 34 MBbls of crude oil. The downward revisions were the result of lower pricing and reduced asset performance. Proved undeveloped reserves of 268 MBoe were transferred to proved developed reserves in 2012 due to the reclassification of the Partnership's estimated Wattenberg behind pipe reserves as a result of the Managing General Partner's determination of the cost of a recompletion becoming less significant as compared to the cost of drilling a new well. There were no proved undeveloped reserves developed in 2012. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2012.

51

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited

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

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

This Partnership is engaged solely in crude oil and natural gas activities, all of which are located in the continental United States. Drilling operations began upon funding in August 2007. This Partnership currently owns an undivided working interest in 75 gross (73.9 net) productive crude oil and natural gas wells located in the Wattenberg Field within the Denver-Julesburg Basin, north and east of Denver, Colorado.

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

	As of December 31,
	2013			2012 (1)
Leasehold costs	$	1,965,081		$	2,016,120
Development costs (2)	53,783,668			77,585,529
Crude oil and natural gas properties, successful efforts method, at cost	55,748,749			79,601,649
Less: Accumulated DD&A	(31,819,541		)	(38,868,788		)
Crude oil and natural gas properties, net	$	23,929,208		$	40,732,861

⁽¹⁾ Includes Piceance Basin crude oil and natural gas properties of $23,843,000, and related accumulated DD&A of $10,171,000, divested in 2013. See Note 11, Divestiture and Discontinued Operations, for further information.

⁽²⁾ Includes estimated costs associated with this Partnership's asset retirement obligations. See Note 6, Asset Retirement Obligations, for further information.

This Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of crude oil and natural gas or environmental protection. This Partnership also invests in equipment and services to complete refracturing or recompletion opportunities pursuant to the Additional Development Plan. There were no investments for this Partnership in 2013. Substantially all of the $3.2 million investment in 2012 is attributable to activities pursuant to the Additional Development Plan.

This Partnership recorded an impairment charge of $2,191,002 for the year ended December 31, 2012 associated with its Piceance Basin proved oil and natural gas properties. Accordingly, this Partnership reduced crude oil and natural gas properties by $3,820,877 and related accumulated depreciation, depletion and amortization for those properties by $1,629,875 as of December 31, 2012. See Note 10, Impairment of Capitalized Costs, for additional disclosure related to this Partnership's proved property impairment.

52

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

FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

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

(a) Evaluation of Disclosure Controls and Procedures

As of December 31, 2013, PDC, as Managing General Partner on behalf of this Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of this Partnership's disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that this Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, and that such information is accumulated and communicated to this Partnership's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.

Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and the Chief Financial Officer concluded that this Partnership's disclosure controls and procedures were effective as of December 31, 2013.

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

Management of PDC, the Managing General Partner of this 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 this Partnership's internal control over financial reporting as of December 31, 2013, based upon the criteria established in “Internal Control - Integrated Framework (1992)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management of the Managing General Partner concluded that this Partnership maintained effective internal control over financial reporting as of December 31, 2013.

53

Exchange Act Rules 13a-15(c) and 15d - 15(c) and Section 404 of the Sarbanes-Oxley Act of 2002 require management of this Partnership to conduct an annual evaluation of this 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 this Partnership is neither an accelerated filer nor a large accelerated filer as defined by SEC regulations, this Partnership's internal control over financial reporting was not subject to attestation by this Partnership's independent registered public accounting firm. As such, this Annual Report on Form 10-K does not contain an attestation report of this 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, 2013, PDC, the Managing General Partner, made no changes in this Partnership's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect this Partnership's internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

This Partnership has no employees of its own and has authorized the Managing General Partner to manage this 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 this Partnership, with respect to services rendered in their capacity to act on behalf of this 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 "PDCE." The business and affairs of this 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 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.

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 Board. The Audit Committee also 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.

Managing General Partner Duties and Resource Allocation

As the Managing General Partner, PDC actively manages and conducts the business of this 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, to conduct the primary business affairs of this Partnership, including the following:

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

• Market-responsive crude oil and natural gas 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 this 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. 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.pdce.com. Any required disclosure regarding amendments to or waivers of the Code of Conduct will be posted on that site.

The Corporate Governance section of the Managing General Partner's website contains additional information including written charters for each Board committee and Board corporate governance guidelines. 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 filed these financial statements filed with the SEC on its website.

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Section 16(a) Beneficial Ownership Reporting Compliance

During the fiscal year ended December 31, 2013, no person subject to the requirements of Section 16(a) under the Securities Exchange Act of 1934 failed to file a report required thereunder.

PDC Energy, Inc.

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	65	Chief Executive Officer, President and Director	2009	2016
Gysle R. Shellum	62	Chief Financial Officer	—	—
R. Scott Meyers	39	Chief Accounting Officer	—	—
Barton R. Brookman, Jr.	51	Executive Vice President and Chief Operating Officer	—	—
Daniel W. Amidon	53	Senior Vice President, General Counsel and Secretary	—	—
Lance Lauck	51	Senior Vice President Corporate Development	—	—
Jeffrey C. Swoveland	58	Non-Executive Chairman	1991	2014
Joseph E. Casabona	70	Director	2007	2014
Anthony J. Crisafio	61	Director	2006	2015
Larry F. Mazza	53	Director	2007	2016
David C. Parke	47	Director	2003	2014
Kimberly Luff Wakim	55	Director	2003	2015

James M. Trimblewas appointed Chief Executive Officer and President of PDC in June 2011, having served on the Board since 2009. From August 2005 until November 2010, Mr. Trimble served as Managing Director of Grand Gulf Energy, Limited (ASX: GGE) ("Grand Gulf"), a public company traded on the Australian Securities Exchange, and retired from the Board of Directors of Grand Gulf in November 2011. In January 2005, Mr. Trimble founded and served until November 2010 as President and Chief Executive Officer of Grand Gulf's 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 TexCal Energy LLC, both of which were privately held oil and gas companies that he managed 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 and gas company with operations in the Gulf of Mexico. Mr. Trimble currently serves on the Board of Directors of Seisgen Exploration LLC, a small private exploration and production company operating in southern Texas.

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Gysle R. Shellumwas appointed Chief Financial Officer of PDC in November 2008. Prior to joining PDC, Mr. Shellum served from September 2004 through September 2008 as Vice President, Finance and Special Projects of Crosstex Energy, L.P. in Dallas, Texas. 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 holds a B.B.A. in Accounting from the University of Texas, Arlington.

R. Scott Meyerswas appointed Chief Accounting Officer of PDC in April 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 Executive Vice President and Chief Operating Officer of PDC in June 2013. Previously, Mr. Brookman served as Senior Vice President Exploration and Production of PDC from March 2008 to June 2013, and prior to that as Vice President Exploration and Production, having joined PDC in July 2005. Prior to joining PDC, Mr. Brookman worked for Patina Oil and Gas and its predecessor Snyder Oil from 1988 until 2005 in a series of operational and technical positions of increasing responsibility, ending his service at Patina as Vice President of Operations. Mr. Brookman holds a B.S. in Petroleum Engineering from the Colorado School of Mines and a M.S. in Finance from the University of Colorado.

Daniel W. Amidonwas appointed General Counsel and Secretary of PDC in July 2007 and Senior Vice President in 2012. Prior to joining PDC, Mr. Amidon was employed by Wheeling-Pittsburgh Steel Corporation beginning in July 2004, where he served in several positions including General Counsel and Secretary. Prior to his employment with Wheeling-Pittsburgh Steel, Mr. Amidon was employed by 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. Mr. Amidon graduated from University of Virginia, with honors, majoring in economics. He received his J.D. from the Dickinson School of Law (currently named Penn State Law).

Lance A. Lauckwas appointed Senior Vice President Corporate Development of PDC in January 2012. Previously, Mr. Lauck served as Senior Vice President Business Development, having joined PDC in August 2009. Mr. Lauck has overall responsibility for PDC's business development, strategic planning, corporate reserves, and midstream and marketing. Previously, he served as Vice President — Acquisitions and Business Development for Quantum Resources Management LLC from 2006 to 2009. From 1988 until 2006, Mr. Lauck worked for Anadarko Petroleum Corporation, where he initially held production, reservoir and acquisition engineering positions before assuming various management-level positions in the areas of acquisitions and business development, ending his service as General Manager, Corporate Development. From 1984 to 1988, Mr. Lauck worked as a production engineer for Tenneco Oil Company. Mr. Lauck holds a B.S. in Petroleum Engineering from the University of Missouri-Rolla.

Jeffrey C. Swoveland was elected Non-Executive Chairman of the Board, a newly created position, in June 2011, having served on the Board since 1991. He 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 also has worked as a geologist and exploratory geophysicist for both major and independent oil and gas companies. 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 Special Transaction Committee of the Board, which he Chairs, the Audit Committee and the Compensation Committee.

Joseph E. Casabona served as Executive Vice President and member of the Board of Directors of Denver-based Energy Corporation of America (“ECA”) from 1985 until his retirement in May 2007. ECA is a privately-held energy company that owns and operates assets both in the U.S. and around the world, including approximately 4,600 wells, 5,000 miles of pipeline and 1,000,000 acres in North America. As the primary direct report to the Chief Executive Officer of ECA, Mr. Casabona’s major responsibilities included strategic planning/forecasting, acquisitions, capital transactions, corporate policy and executive oversight in operational and drilling activities in the continental U.S. and internationally. From 1968 until 1985, Mr. Casabona was employed at KPMG or its predecessors, with various titles including audit partner in the Pittsburgh, Pennsylvania office, where he primarily serviced public clients in the oil and gas industry. From 2008 until the beginning of 2011, Mr. Casabona served as Chief Executive Officer of Paramax Resources Ltd, a junior public Canadian oil and gas company engaged in the business of acquiring and exploring oil and gas prospects, primarily in Canada and Idaho. Mr. Casabona serves on the Audit Committee of the Board, which he Chairs.

57

Anthony J. Crisafio, a Certified Public Accountant, has served as an independent business consultant for more than seventeen years, providing financial and operational advice to businesses in a variety of industries and stages of development. He is currently serving as part-time contract Chief Financial Officer for Empire Energy USA, LLC, which has operations in the Central Kansas Uplift and the shallow Appalachian Basin primarily in the State of New York, and is currently seeking and has pursued acquisitions in a variety of other basins in the United States.  Mr. Crisafio also serves as Chief Financial Officer for MDS Energy (“MDS”), a part-time position.  MDS and its affiliates have acreage and operations primarily in western Pennsylvania.  He also serves as an 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 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 SEC registered client engagements and gained significant experience with oil and gas industry clients and mergers and acquisitions. Mr. Crisafio serves on the Compensation Committee and the Special Transaction Committee of the Board.

Larry F. Mazza is President and Chief Executive Officer of MVB Financial Corp ("MVB"), a growing financial services company with banking, mortgage, insurance and wealth management operations in West Virginia and Northern Virginia.  He has more than 26 years of experience in both large banks and small community banks. Mr. Mazza is one of seven members of the West Virginia Board of Banking and Financial Institutions. This Board oversees the operation of financial institutions throughout West Virginia, and advises the state Commissioner of Banking on banking matters. Mr. Mazza is also an entrepreneur, and is co-owner of nationally-recognized sports media business Football Talk, LLC, a pro football website as well as content provider for NBC SportsTalk. Prior to joining MVB in 2005 to lead its geographic expansion and growth, Mr. Mazza was Senior Vice President & Retail Banking Manager for BB&T Bank’s West Virginia North region, consisting of 33 financial centers and more than 300 employees. Mr. Mazza was employed by BB&T and its predecessors from 1986 to 2005. Prior thereto, Mr. Mazza was President of Empire National Bank, and later served as Regional President of One Valley Bank, a state-wide financial institution. Upon graduation from West Virginia University in Business Administration, he worked for KPMG (or its predecessors) as a Certified Public Accountant with a focus on auditing.  In determining Mr. Mazza's qualifications to serve on our Board, the Board has considered Mr. Mazza's extensive leadership and banking experience.  Banking relationships and experience have become particularly important to the Company in recent years.  The Company benefits from Mr. Mazza's first-hand continuing experience as a chief executive officer, a specific attribute sought by the Board when he initially became a Director in 2007.  Mr. Mazza also provides an important link to community and employee stakeholders, demonstrating a continuing commitment to our workforce located in Bridgeport, West Virginia.

David C. Parke has served as Managing Director in the investment banking group of Burrill & Company since June 2011. From 2006 until 2011, he was Managing Director in the investment banking group of Boenning & Scattergood, Inc., a regional investment bank. Prior to joining Boenning & Scattergood, he was a Director with investment banking firm Mufson Howe Hunter & Company LLC, 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., both 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 Wells Fargo, and Legg Mason, Inc., now part of Stifel Nicolaus. Mr. Parke served on the board of directors of Zunicom, Inc., a public company, from 2006 until December 2007. Mr. Parke serves on the Compensation Committee of the Board, the Nominating and Governance Committee and the Special Transaction 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 is the Practice Group Leader for the Bankruptcy and Financial Restructuring Practice Group. She has practiced law with Thorp, Reed & Armstrong 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 the American Institute of Certified Public Accountants and the West Virginia Society of CPAs for more than twenty years. Ms. Wakim serves on the Compensation Committee of the Board, which she Chairs, the Audit Committee and the Nominating and Governance Committee.

Audit Committee

The Audit Committee of the Board 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. Joseph E. Casabona chairs the Audit Committee. Other members are Directors Swoveland and Wakim. The Board has determined that all three members of the Audit Committee qualify as financial experts as defined by SEC regulations and are independent of management.

Other

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           The Board has determined that, other than Mr. Trimble, each member of the Board is independent under NASDAQ Listing Rule 5605(a)(2), and therefore that each member of the Audit Committee, the Compensation Committee and the Nominating and Governance Committee of the Board is independent under that rule. The Nominating and Governance Committee will consider candidates for director of PDC recommended investors on the same basis as those recommended by other sources as described in PDC’s proxy statements relating to its annual meetings of stockholders.

ITEM 11. EXECUTIVE COMPENSATION

This 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 this 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 this Partnership, is reasonably likely to have a materially adverse effect on this Partnership's operations or conduct of PDC when carrying out duties and responsibilities to this 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 this Partnership are not used to directly compensate or reimburse PDC's officers or directors. No management fee was paid to PDC in 2013 or 2012 as this 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. This 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 this Partnership by the Managing General Partner. See Item 13, Certain Relationships and Related Transactions and Director Independence, for a discussion of compensation paid by this Partnership to the Managing General Partner.

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

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

RELATED STOCKHOLDER MATTERS

The following table presents information as of December 31, 2013, concerning the Managing General Partner's interest in this Partnership and other persons known by this Partnership to own beneficially more than 5% of the interests in this 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
PDC Energy, Inc. (2) (3) (4) (5)	—	41.3	0.92	%	0.58	%

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

(2) PDC Energy, Inc., 1775 Sherman Street Suite 3000, Denver, Colorado 80203.

(3) No director or officer of PDC owns an interest in limited partnerships sponsored by PDC. Pursuant to the 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 this Partnership. [(41.3 units/4,470 units)*63% limited partnership ownership]

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR

INDEPENDENCE

Compensation to the Managing General Partner

The Managing General Partner transacts all of this Partnership's business on behalf of this 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 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. 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 this Partnership at the lesser of cost or competitive prices in the area of operations.

Industry specialists employed by PDC to support this 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 this Partnership for costs and expenses related to the purchase or repairs of equipment, materials, third-party services, brine disposal and 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, water trucks, 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 this Partnership.

See Note 9, Transactions with Managing General Partner, to the financial statements included elsewhere in this report for information regarding compensation to and transactions with the Managing General Partner.

Related Party Transaction Policies and Approval

The Agreement and the D&O Agreement with PDC govern related party transactions, including those described above. This 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

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

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents amounts charged by this Partnership's independent registered public accounting firm, PricewaterhouseCoopers LLP, for the years described:

	Year ended December 31,
Type of Service	2013		2012
Audit Fees (1)	$	165,000	$	165,000

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

Audit Committee Pre-Approval Policies and Procedures

The Sarbanes-Oxley Act of 2002 requires that all services provided to this Partnership by its independent registered public accounting firm be subject to pre-approval by the Audit Committee of the Board or authorized members of the Committee. This 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 this 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 PDC's website under Corporate Governance. All of the fees in the above table were approved by the Audit Committee in accordance with its pre-approval policies.

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PART IV

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)    The index to Financial Statements is located on page 31.

(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 this Partnership under West Virginia law	10-12G/A Amend 1	000-53201	3.1	08/06/2008
10.1	Drilling and operating agreement between this Partnership and PDC, as Managing General Partner	10-12G/A Amend 1	000-53201	10.2	08/06/2008
10.2	Form of assignment of leases to this Partnership	10-12G/A Amend 1	000-53201	10.1	08/06/2008
10.3	Audited Consolidated Financial Statements for the year ended December 31, 2013 of PDC Energy, Inc. and its subsidiaries, as Managing General Partner of this Partnership	10-K	000-07246		02/20/2014
10.4	Purchase and Sale Agreement by and among the Company, affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated February 4, 2013.	8-K	000-07246	10.1	05/1/2013
10.5	Amendment No. 1 to Purchase and Sale Agreement, dated as of May 30, 2013, by and among the Company, certain affiliates of the Company, Caerus Operating LLC, Caerus Washco LLC and Caerus Piceance LLC.	8-K	000-07246	10.1	06/3/2013

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

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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

PDC Energy, Inc.

By: /s/ James M. Trimble

James M. Trimble

Chief Executive Officer and President

of PDC Energy, Inc.

April 4, 2014

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

Signature	Title	Date
/s/ James M. Trimble	Chief Executive Officer, President and Director	April 4, 2014
James M. Trimble	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	April 4, 2014
Gysle R. Shellum	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	April 4, 2014
R. Scott Meyers	PDC Energy, Inc. Managing General Partner of the Registrant
	(Principal accounting officer)
/s/ Jeffrey C. Swoveland	Chairman and Director	April 4, 2014
Jeffrey C. Swoveland	PDC Energy, Inc.
	Managing General Partner of the Registrant
/s/ Joseph E. Casabona	Director	April 4, 2014
Joseph E. Casabona	PDC Energy, Inc.
	Managing General Partner of the Registrant
/s/ Kimberly Luff Wakim	Director	April 4, 2014
Kimberly Luff Wakim	PDC Energy, Inc.
	Managing General Partner of the Registrant

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EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James M. Trimble, certify that:

1. I have reviewed this Annual Report on Form 10-K 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:  April 4, 2014

/s/ James M. Trimble

James M. Trimble

Chief Executive Officer and President

PDC Energy, Inc.

Managing General Partner

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Gysle R. Shellum, certify that:

1. I have reviewed this Annual Report on Form 10-K 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:  April 4, 2014

/s/ Gysle R. Shellum

Gysle R. Shellum

Chief Financial Officer
PDC Energy, Inc.
Managing General Partner

EX-32.1

Exhibit 32.1

CERTIFICATION

FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES OXLEY ACT OF 2002

In connection with the Annual Report of Rockies Region 2007 Limited Partnership (the “Registrant”) on Form 10-K for the period ended December 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned certify pursuant to Section 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	April 4, 2014
James M. Trimble
Chief Executive Officer and President
PDC Energy, Inc.
Managing General Partner
/s/ Gysle R. Shellum	April 4, 2014
Gysle R. Shellum
Chief Financial Officer
PDC Energy, Inc.
Managing General Partner

EX-99.1

Exhibit No. 99.1

February 6, 2014

PDC Energy

120 Genesis Boulevard

Bridgeport, WV 26330

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of PDC Energy’s (“PDC”) RR07LP as of December 31, 2013. 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 6, 2014and 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 represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of PDC Energy RR07LP as of December 31, 2013.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2013, 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 Interests of

PDC RR07LP

As of December 31, 2013
	Proved
	Developed				Total
	Producing		Non-Producing		Proved
Net Remaining Reserves
Oil/Condensate - Barrels	323,292		345,110		668,402
Plant Products - Barrels	153,066		346,309		499,375
Gas - MMCF	1,497		3,219		4,716
Income Data (M$)
Future Gross Revenue	$	34,797	$	47,107	$	81,904
Deductions	16,175		25,758		41,933
Future Net Income (FNI)	$	18,622	$	21,349	$	39,971
Discounted FNI @ 10%	$	12,465	$	6,160	$	18,625

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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 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 and certain abandonment costs net of salvage. At the clients’ request abandonment costs are shown under the “other deductions” column. 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 hydrocarbons reserves account for approximately 81 percent and gas reserves account for the remaining 19 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, 2013
Discount Rate		Total
Percent		Proved
5		$26,132
15		$14,229
20		$11,479
25		$9,656

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 Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the behind pipe category.

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

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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. At PDC’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. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, 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 ownsan 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.

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. Reserve evaluators 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.

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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 and analogy methods. One hundred percent of the proved producing reserves attributable to producing wells were estimated by performance methods.The performance method included was decline curve analysis which utilized extrapolations of historical production data available through December 2013. The data utilized in this analysis were furnished to Ryder Scott by PDC and were considered sufficient for the purpose thereof.

One hundred percent of the proved developed non-producing reserves included herein were estimated by analogy. The data utilized from theanalogues were considered sufficient for the purpose thereof.

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 that 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 furnished 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

PDC Energy - PDC RR07LP

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Page 5

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.

The future production rates from wells currently on production or wells 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.

PDCfurnished us with the above mentioned average prices in effect on December 31, 2013. 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 that 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 feesand/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by PDC. 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.

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Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$96.94/Bbl	$81.91/Bbl
	NGLs	WTI Cushing	$96.94/Bbl	$23.14/Bbl
	Gas	Henry Hub	$3.67/MMBTU	$3.38/MCF

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

Costs

Operating costs for the leases and wells in this report were furnished to us by PDC and 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 and are shown under the “other deductions” column. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for PDC’s estimate.

The proved developed non-producing reserves in this report have been incorporated herein in accordance with PDC’s plans to develop these reserves as of December 31, 2013. The implementation of PDC’s development plans as presented to us and incorporated herein is subject to the approval process adopted by PDC’s management. As the result of our inquiries 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-five 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 privately-owned or publicly-traded oil and gas company and are separate and independent from the

PDC Energy - PDC RR07LP

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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.

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 PDC 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 RR07LP.

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.

Very truly yours,

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. Richard J. Marshall was the primary technical person responsible for overseeing the estimate of the future net reserves and income.

Marshall, an employee of Ryder Scott Company, L.P. (Ryder Scott) beginning in 1981, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies. Before joining Ryder Scott, Marshall served in a number of engineering positions with Texaco, Phillips Petroleum, and others. For more information regarding Mr. Marshall’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Marshall earned a B.S. in Geology from the University of Missouri in 1974 and a M.S. in Geological Engineering from the University of Missouri at Rolla in 1976. Marshall is a registered Professional Engineer in the State of Colorado. He is a member of the Society of Petroleum Engineers, Wyoming Geological Association, Rocky Mountain Association of Geologists and the Society of Petroleum Evaluation Engineers.

Based on Marshall’s educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Marshall has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as 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

Transactions with Managing General Partner Related Party Transactions (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Rate		Dec. 31, 2012
Related Party Transaction [Line Items]
Direct costs - general and administrative	$ 209,500		$ 200,972
Investor Partner Ownership Interest	63.00%
Managing General Partner, Ownership Interest Before Unit Repurchases	37.00%
Managing General Partner
Related Party Transaction [Line Items]
Well operations and maintenance	1,660,093	[1]	2,260,438	[1]
Gathering, compression and processing fees	119,017	[2]	339,542	[2]
Direct costs - general and administrative	535,551	[3]	200,972	[3]
Refracturing and recompletion costs	0	[4]	3,159,943	[4]
Cash distributions	7,819,797	[5]	2,658,297	[5]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 100,277		$ 17,636

[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 this 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 this 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 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. 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 this 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 this Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between this 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 crude oil, natural gas and NGLs, such as: •well tending, routine maintenance and adjustment;•reading meters, recording production, pumping, maintaining appropriate books and records; and•preparing production related reports to this 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; or•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 may enter into other transactions with this Partnership for services, supplies and equipment during the production phase of this 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 this 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, this 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, this Partnership pays the gathering fee charged by the third-party gathering the natural gas.

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

[4] Refracturing and recompletion costs relate to expenditures recorded pursuant to the Additional Development Plan.

[5] 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 the years ended December 31, 2013 and 2012 include $100,277 and $17,636, respectively, related to equity cash distributions 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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Concentration of Risk Concentration of Risk (Details)	12 Months Ended
	Dec. 31, 2013 Rate	Dec. 31, 2012 Rate
Suncor Energy Marketing, Inc.
Concentration Risk - Revenue
Major Accounts Receivable Customer Percentage	76.00%
Percentage of Partnership Revenue	82.00%	84.00%
DCP Midstream, LP [Member]
Concentration Risk - Revenue
Major Accounts Receivable Customer Percentage	22.00%
Percentage of Partnership Revenue	18.00%	16.00%

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Partners' Equity and Cash Distributions Cash Distributions (Tables)

12 Months Ended

Dec. 31, 2013

Distributions made to limited partner and managing partner of limited partnership. [Line Items]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:

	Year ended December 31,
	2013		2012
Cash distributions	$	20,863,568	$	7,136,923

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Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Price Used to Estimate Reserves (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Crude Oil (MBbl)
Reserve Quantities [Line Items]
Price Used to Estimate Reserves	$ 81.91	[1]	$ 87.51	[1]
Natural Gas (MMcf)
Reserve Quantities [Line Items]
Price Used to Estimate Reserves	3.38	[1]	2.31	[1]
Natural Gas Liquids (MBbl)
Reserve Quantities [Line Items]
Price Used to Estimate Reserves	$ 23.14	[1]	$ 23.07	[1]

[1] The prices used to estimate reserves have been prepared in accordance with the SEC. 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 this Partnership's year-end estimated proved reserves. Prices for each of the two years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of this Partnership's commodity derivatives.

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Partners' Equity and Cash Distributions Cash Distributions (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Rate	Dec. 31, 2012
Distributions made to limited partner and managing partner of limited partnership. [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	$ 13,500,000
Investor Partner Ownership Interest	63.00%
Managing General Partner, Ownership Interest Before Unit Repurchases	37.00%
Partners' Capital Account Distributions During the Year	$ 20,863,568	$ 7,136,923
Performance Standard Obligation of Managing General Partner
Percentage of Obligated Unit Repurchases	10.00%

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments

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

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

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

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

Derivative instruments that were due to mature subsequent to June 30, 2013 were either liquidated or sold to Caerus during the quarter ended June 30, 2013. See Note 11, Divestitures and Discontinued Operations, for additional information regarding transactions with Caerus. Accordingly, as of December 31, 2013, this Partnership did not have any derivative instruments in place for its future production. When applicable, the Managing General Partner measured the fair value of this Partnership's derivative instruments based on a pricing model that utilized market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas forward curve, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validated its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While the Managing General Partner used common industry practices to develop its valuation techniques, and believed this Partnership's valuation method was appropriate and consistent with those used by other market participants, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values.

This Partnership's fixed-price swaps and basis swaps as of December 31, 2012 were included in Level 2. The following table presents this Partnership's derivative assets and liabilities that had been measured at fair value on a recurring basis:

	Balance Sheet	December 31, 2012
	Line Item	Level 2
Assets:
Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	4,409,574
Total assets		4,409,574
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	2,004,594
Total liabilities		2,004,594
Net asset		$	2,404,980

Non-Derivative Financial Assets and Liabilities

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

See Note 2, Summary of Significant Accounting Policies, Crude Oil and Natural Gas Properties and Asset Retirement Obligations, for a discussion of how this Partnership determined fair value for these assets and liabilities.

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Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Schedule of Developed and Undeveloped Reserves (Details)	12 Months Ended
	Dec. 31, 2013 MMcf		Dec. 31, 2012 MMcf
Natural Gas (MMcf)
Reserve Quantities [Line Items]
Proved reserves, January 1,	13,036	[1]	18,415
Revisions of previous estimates and reclassifications	(712)		(3,926)
Dispositions	(6,874)	[1]
Production	(734)		(1,453)
Proved reserves, December 31,	4,716		13,036	[1]
Proved Developed Reserves	4,716		13,036
Natural Gas (MMcf) | Piceance and NECO Asset Group
Reserve Quantities [Line Items]
Proved reserves, December 31,	7,390
Natural Gas Liquids (MBbl)
Reserve Quantities [Line Items]
Proved reserves, January 1,	595	[1]	697
Revisions of previous estimates and reclassifications	(74)		(81)
Dispositions	0	[1]
Production	(22)		(21)
Proved reserves, December 31,	499		595	[1]
Proved Developed Reserves	499		595
Crude Oil (MBbl)
Reserve Quantities [Line Items]
Proved reserves, January 1,	853	[1]	879
Revisions of previous estimates and reclassifications	(117)		34
Dispositions	(15)	[1]
Production	(53)		(60)
Proved reserves, December 31,	668		853	[1]
Proved Developed Reserves	668		853
Crude Oil (MBbl) | Piceance and NECO Asset Group
Reserve Quantities [Line Items]
Proved reserves, December 31,	17
Crude Oil Equivalent (MBoe)
Reserve Quantities [Line Items]
Proved reserves, January 1,	3,621	[1]	4,645
Revisions of previous estimates and reclassifications	(310)		(701)
Dispositions	(1,161)	[1]
Production	(197)		(323)
Proved reserves, December 31,	1,953		3,621	[1]
Proved Developed Reserves	1,953		3,621
Crude Oil Equivalent (MBoe) | Piceance and NECO Asset Group
Reserve Quantities [Line Items]
Proved reserves, December 31,	1,249

[1] Includes estimated reserve data related to this Partnership's Piceance Basin assets. In June 2013, this Partnership's Piceance Basin crude oil and natural gas properties were divested. See Note 11, Divestiture and Discontinued Operations, for additional information regarding this divestiture. As of December 31, 2012, total proved reserves related to this Partnership's Piceance Basin assets include 7,390 MMcf of natural gas and 17 MBbl of crude oil, for an aggregate of 1,249 MBoe of crude oil equivalent.

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General and Basis of Presentation General and Basis of Presentation (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Rate Number_of_Limited_Partners
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Limited Partners	1,783
Managing General Partner, Ownership Interest Before Unit Repurchases	37.00%
Investor Partner Ownership Interest	63.00%
Limited Partner Units Repurchased by Managing General Partner	41.3
Average Price Paid for Units Repurchased by Managing General Partner	$ 4,269
Managing General Partner Ownership Interest	37.60%

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Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited (Tables)

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Prices Used to Estimate Crude Oil and Natural Gas Reserves [Table Text Block]

The following table presents the prices used to estimate this Partnership's reserves, by commodity:

	Price Used to Estimate Reserves (1)
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2013	$	81.91	$	3.38	$	23.14
2012	87.51		2.31		23.07

(1) The prices used to estimate reserves have been prepared in accordance with the SEC. 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 this 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 this Partnership's commodity derivatives.

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

The following table presents the changes in estimated quantities of this Partnership's reserves, all of which are located within the United States:

	Natural Gas		NGLs		Crude Oil and Condensate		Crude Oil Equivalent
	(MMcf)		(MBbl)		(MBbl)		(MBoe)
Proved Reserves:
Proved reserves, January 1, 2012	18,415		697		879		4,645
Revisions of previous estimates and reclassifications	(3,926	)	(81	)	34		(701	)
Production	(1,453	)	(21	)	(60	)	(323	)
Proved reserves, December 31, 2012 (1)	13,036		595		853		3,621
Revisions of previous estimates and reclassifications	(712	)	(74	)	(117	)	(310	)
Dispositions (1)	(6,874	)	—		(15	)	(1,161	)
Production	(734	)	(22	)	(53	)	(197	)
Proved reserves, December 31, 2013	4,716		499		668		1,953
Proved Developed Reserves, as of:
December 31, 2012	13,036		595		853		3,621
December 31, 2013	4,716		499		668		1,953

(1) Includes estimated reserve data related to this Partnership's Piceance Basin assets. In June 2013, this Partnership's Piceance Basin crude oil and natural gas properties were divested. See Note 11, Divestiture and Discontinued Operations, for additional information regarding this divestiture. As of December 31, 2012, total proved reserves related to this Partnership's Piceance Basin assets include 7,390 MMcf of natural gas and 17 MBbl of crude oil, for an aggregate of 1,249 MBoe of crude oil equivalent.

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

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

	As of December 31,
	2013			2012 (1)
Leasehold costs	$	1,965,081		$	2,016,120
Development costs (2)	53,783,668			77,585,529
Crude oil and natural gas properties, successful efforts method, at cost	55,748,749			79,601,649
Less: Accumulated DD&A	(31,819,541		)	(38,868,788		)
Crude oil and natural gas properties, net	$	23,929,208		$	40,732,861

⁽¹⁾ Includes Piceance Basin crude oil and natural gas properties of $23,843,000, and related accumulated DD&A of $10,171,000, divested in 2013. See Note 11, Divestiture and Discontinued Operations, for further information.

⁽²⁾ Includes estimated costs associated with this Partnership's asset retirement obligations. See Note 6, Asset Retirement Obligations, for further information.

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Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Wells		Dec. 31, 2012
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Leasehold costs	$ 1,965,081		$ 2,016,120	[1]
Development costs	53,783,668	[2]	77,585,529	[1],[2]
Crude oil and natural gas properties, successful efforts method, at cost	55,748,749		79,601,649	[1]
Less: Accumulated depreciation, depletion and amortization	(31,819,541)		(38,868,788)	[1]
Natural gas and crude oil properties, net	23,929,208		40,732,861	[1]
Additional Information:
Reimbursement to Managing General Partner			3,100,000
Gross productive natural gas and crude oil wells	75
Net productive natural gas and crude oil wells	73.9
Capital expenditures for crude oil and natural gas properties	0		3,162,158
Reduction in Natural Gas and Crude Oil Properties ($)			3,820,877
Reduction in Accumulated Depreciation, Depletion and Amortization ($)			1,629,875
Piceance and NECO Asset Group [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude oil and natural gas properties, successful efforts method, at cost			23,843,000
Less: Accumulated depreciation, depletion and amortization			10,171,000
Discontinued Operations [Member]
Additional Information:
Impairment of crude oil and natural gas properties	$ 0		$ 2,191,002

[1] Includes Piceance Basin crude oil and natural gas properties of $23,843,000, and related accumulated DD&A of $10,171,000, divested in 2013. See Note 11, Divestiture and Discontinued Operations, for further information.

[2] Includes estimated costs associated with this Partnership's asset retirement obligations. See Note 6, Asset Retirement Obligations, for further information.

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) (USD $)	Dec. 31, 2013
Cash and Cash Equivalents [Line Items]
Cash, FDIC Insured Amount	$ 250,000

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Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Due from Managing General Partner-derivatives	$ 0	$ 4,409,574
Due to Managing General Partner-derivatives	0	2,004,594
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		4,409,574
Total liabilities		2,004,594
Net asset		2,404,980
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Due from Managing General Partner-derivatives		4,409,574
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Due to Managing General Partner-derivatives		$ 2,004,594

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management's Estimates

The preparation of this Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires this Partnership to make estimates and assumptions that affect the amounts reported in this 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, NGLs and crude oil sales revenue, proved reserves, future cash flows from crude oil, natural gas and NGLs 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 this Partnership.

Cash and Cash Equivalents. This Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. This Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. The balance in this Partnership's account is insured by Federal Deposit Insurance Corporation, up to $250,000. This Partnership has not experienced losses in any such accounts to date and limits this 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. This Partnership's accounts receivable are from purchasers of crude oil, natural gas and NGLs. This Partnership sells substantially all of its crude oil, natural gas and NGLs to customers who purchase crude oil, natural gas and NGLs from other partnerships managed by this 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 for doubtful accounts was deemed necessary at December 31, 2013 or 2012.

Commitments. As Managing General Partner, PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of this 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, this 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. This Partnership is exposed to the effect of market fluctuations in the prices of crude oil and natural gas. The Managing General Partner previously employed established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production. The Managing General Partner's policy prohibits the use of crude oil and natural gas derivative instruments for speculative purposes.

All derivative assets and liabilities were recorded on the balance sheets at fair value. PDC, as Managing General Partner, elected not to designate any of this Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of this Partnership's derivative instruments were recorded in this Partnership's statements of operations and this Partnership's net income was subject to greater volatility than it would have been if this Partnership's derivative instruments had qualified for hedge accounting. The net settlements and the net change in fair value of unsettled derivatives are recorded in the line captioned, “Commodity price risk management gain, net.” As positions designated to this Partnership settled, positive and negative settlements were netted for distribution. Positive settlements were paid to this Partnership and negative settlements were deducted from this Partnership's cash distributions generated from production. This Partnership bore its proportionate share of counterparty risk. As of December 31, 2013, this Partnership had no outstanding derivative instruments.

The validation of the derivative instrument's fair value was performed by the Managing General Partner. While the Managing General Partner used common industry practices to develop this Partnership's valuation techniques, changes in this Partnership's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values. See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, for a discussion of this Partnership's derivative fair value measurements as of December 31, 2012.

Crude Oil and Natural Gas Properties. This Partnership accounts for its crude oil and natural gas 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. This Partnership calculates quarterly DD&A expense by using estimated prior period-end reserves as the denominator, with the exception of this Partnership's fourth quarter where this Partnership uses the year-end reserve estimate adjusted to add back fourth quarter 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 Crude Oil, Natural Gas and NGLs Information - Unaudited,Net Proved Reserves, included at the end of these financial statements and accompanying notes elsewhere in this report for additional information regarding this Partnership's reserve reporting. In accordance with the Agreement, all capital contributed to this Partnership, after deducting syndication costs and a one-time management fee, was used solely for the drilling of crude oil and natural gas wells. This Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of crude oil, natural gas and NGLs 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 this Partnership's properties on a well-by-well basis as of December 31. Additionally, this Partnership adjusts reserves for major well rework or abandonment during the year, as needed. The process of estimating and evaluating crude oil, natural gas and NGLs 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 this 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 this Partnership's DD&A expense, a change in this Partnership's estimated reserves could have an effect on this Partnership's net income or loss.

Proved Property Impairment. Upon a triggering event, this Partnership assesses its producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, 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 crude oil and natural gas. Certain events, including but not limited to, downward revisions in estimates to this 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 this Partnership's proved crude oil and natural gas 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 and is measured by the amount by which the net capitalized costs exceed their fair value. Impairment charges are included in the statement of operations line item impairment of crude oil and natural gas properties, with a corresponding reduction to crude oil and natural gas properties and accumulated depreciation, depletion and amortization line items on the balance sheet.

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 this Partnership produces crude oil, natural gas and NGLs. This Partnership's share of these taxes recorded in the line crude oil, natural gas and NGLs production costs on this Partnership's statements of operations. This Partnership's production taxes payable are included in the caption accounts payable and accrued expenses on this Partnership's balance sheets.

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

Asset Retirement Obligations.This 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 spud. Upon initial recognition of an asset retirement obligation, this 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, net of salvage value, 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 changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 6, Asset Retirement Obligations, for a reconciliation of the changes in this Partnership's asset retirement obligation.

Revenue Recognition. Crude oil, natural gas and NGLs 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. This Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of this Partnership's sales pursuant to which the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells this 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 this Partnership's purchasers and reflected in the wellhead price. The majority of this Partnership's natural gas and NGLs is sold by the Managing General Partner on a long-term basis, primarily over 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 and the quality of the natural gas.

Recent Accounting Standards

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

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Derivative Financial Instruments Derivative Financial Instruments (Details) (Commodity Price Risk Management, net [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Commodity Price Risk Management, net [Member]
Derivative [Line Items]
Net settlements	$ 1,275,544	$ 3,462,935
Net change in fair value of unsettled derivatives	(1,693,233)	(2,384,355)
Total commodity price risk management gain (loss), net	$ (417,689)	$ 1,078,580

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Divestitures and Discontinued Operations Piceance Basin Assets Divestiture (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	$ 13,500,000
Capitalized Costs, Oil and Gas Producing Activities, Gross	55,748,749	79,601,649	[1]
Crude oil and natural gas properties, successful efforts method, at cost	55,748,749	79,601,649
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion and Amortization	31,819,541	38,868,788
Piceance and NECO Asset Group [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Capitalized Costs, Oil and Gas Producing Activities, Gross		23,843,000
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion and Amortization	10,300,000
Gain (Loss) on Disposition of Oil and Gas Property	500,000
Managing General Partner [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	13,500,000
General Partner [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments of Capital Distribution	5,000,000
Limited Partner [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments of Capital Distribution	$ 8,500,000

[1] Includes Piceance Basin crude oil and natural gas properties of $23,843,000, and related accumulated DD&A of $10,171,000, divested in 2013. See Note 11, Divestiture and Discontinued Operations, for further information.

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Balance Sheets Statement (USD $)	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 570,376	$ 570,376
Accounts receivable	378,940	865,944
Crude oil inventory	55,308	42,939
Due from Managing General Partner-derivatives	0	4,409,574
Due from Managing General Partner-other, net	0	800,598
Total current assets	1,004,624	6,689,431
Crude oil and natural gas properties, successful efforts method, at cost	55,748,749	79,601,649
Less: Accumulated depreciation, depletion and amortization	(31,819,541)	(38,868,788)
Crude oil and natural gas properties, net	23,929,208	40,732,861
Other assets	89,630	46,711
Total Assets	25,023,462	47,469,003
Current liabilities:
Accounts payable and accrued expenses	33,041	90,570
Due to Managing General Partner-derivatives	0	2,004,594
Due to Managing General Partner-other, net	119,994	0
Total current liabilities	153,035	2,095,164
Asset retirement obligations	935,813	1,110,093
Total liabilities	1,088,848	3,205,257
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	3,661,859	11,183,638
Limited Partners - 4470 units issued and outstanding	20,272,755	33,080,108
Total Partners' equity	23,934,614	44,263,746
Total Liabilities and Partners' Equity	$ 25,023,462	$ 47,469,003

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Statements of Cash Flows Statement (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income (loss)	$ 534,436	$ (1,379,827)
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	3,276,550	5,439,026
Accretion of asset retirement obligations	75,144	78,907
Net change in fair value of unsettled derivatives	1,693,233	2,384,355
Loss on sale of crude oil and natural gas properties	495,574	0
Impairment of crude oil and natural gas properties	0	2,191,002
Changes in assets and liabilities:
Accounts receivable	487,004	(97,994)
Crude oil inventory	(17,283)	4,308
Other assets	(42,919)	(46,711)
Accounts payable and accrued expenses	(57,529)	(4,959)
Due to Managing General Partner-other, net	130,241	0
Due from Managing General Partner-other, net	800,598	(389,027)
Net cash from operating activities	7,375,049	8,179,080
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	0	(3,162,158)
Proceeds from sale of crude oil and natural gas properties	13,488,519	0
Net cash from investing activities	13,488,519	(3,162,158)
Cash flows from financing activities:
Distributions to Partners	(20,863,568)	(7,136,923)
Net cash from financing activities	(20,863,568)	(7,136,923)
Net change in cash and cash equivalents	0	(2,120,001)
Cash and cash equivalents, beginning of period	570,376	2,690,377
Cash and cash equivalents, end of period	$ 570,376	$ 570,376

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Commitments and Contingencies Commitment and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
Accrued Environmental Loss Contingencies, Current		$ 5,000
Royalty Expense	$ 326,000

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Concentration of Risk Concentration of Risk (Tables)

12 Months Ended

Dec. 31, 2013

Concentration Risk - Revenue

Individual Customers Constituting 10% or more of Total Revenue [Table Text Block]

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

	Year ended December 31,
Major Customer	2013	2012
Suncor Energy Marketing, Inc.	82%	84%
DCP Midstream, LP	18%	16%

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Partners' Equity and Cash Distributions Partners' Equity and Cash Distributions (Details)	12 Months Ended
	Dec. 31, 2013 Rate
Investor Partners
Allocation of Partners' Interest
Crude oil, natural gas and NGLs sales	63.00%
Commodity price risk management gain (loss)	63.00%
Sale of Productive Properties	63.00%
Sale of Equipment	63.00%
Interest Income	63.00%
Crude Oil, Natural Gas and NGLs Production and Well Operations Costs	63.00%	[1]
Depreciation, Depletion and Amortization Expense	63.00%
Accretion of Asset Retirement Obligations	63.00%
Direct Costs - General and Administrative	63.00%	[2]
Managing General Partner
Allocation of Partners' Interest
Crude oil, natural gas and NGLs sales	37.00%
Commodity price risk management gain (loss)	37.00%
Sale of Productive Properties	37.00%
Sale of Equipment	37.00%
Interest Income	37.00%
Crude Oil, Natural Gas and NGLs Production and Well Operations Costs	37.00%	[1]
Depreciation, Depletion and Amortization Expense	37.00%
Accretion of Asset Retirement Obligations	37.00%
Direct Costs - General and Administrative	37.00%	[2]

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

[2] The Managing General Partner receives monthly reimbursement from this Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of this Partnership.

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Partners' Equity and Cash Distributions (Tables)

12 Months Ended

Dec. 31, 2013

Allocation of Partners' Interest

Allocation of Partner Interest [Table Text Block]

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

			Managing
	Investor		General
	Partners		Partner
Partnership Revenue:
Crude oil, natural gas and NGLs 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:
Crude oil, natural gas and NGLs 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 this Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of this Partnership.

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General and Basis of Presentation

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

GENERAL

Rockies Region 2007 Limited Partnership was organized in 2007 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 crude oil and natural gas properties. Business operations commenced upon closing of an offering for the private placement of Partnership units. Upon funding, this Partnership entered into a D&O Agreement with the Managing General Partner which authorizes PDC to conduct and manage this Partnership's business. In accordance with the terms of the Agreement, the Managing General Partner is authorized to manage all activities of this Partnership and initiates and completes substantially all Partnership transactions.

As of December 31, 2013, there were 1,783 Investor Partners in this Partnership. PDC is the designated Managing General Partner of this Partnership and owns a 37% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 63% to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership, and 37% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. For more information about the Managing General Partner's limited partner unit repurchase program, see Note 8, Partners' Equity and Cash Distributions. Through December 31, 2013, the Managing General Partner had repurchased 41.3 units of Partnership interests from the Investor Partners at an average price of $4,269 per unit. As of December 31, 2013, the Managing General Partner owned 37.6% of this Partnership.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. These reclassifications had no impact on previously reported cash flows, net income, earnings per investor partner unit or partners' equity.

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Balance Sheet Parentheticals (Parentheticals)	Dec. 31, 2013	Dec. 31, 2012
Balance Sheet Parentheticals [Abstract]
Limited Partners' Capital Account, Units Issued	4,470.00	4,470.00
Limited Partners' Capital Account, Units Outstanding	4,470.00	4,470.00

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Divestitures and Discontinued Operations Divestitures and Discontinued Operations (Notes)

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

Piceance Basin. In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $13.5 million. The divestiture of this Partnership's Piceance Basin assets resulted in a decrease of crude oil and natural gas properties of $23.8 million and a decrease of accumulated depreciation, depletion and amortization of $10.3 million. The sale resulted in a loss on divestiture of assets of approximately $0.5 million, which is included in discontinued operations.

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture to the Managing General Partner and Investor Partners as follows:

	Amount
Distributed to:	(millions)
Managing General Partner	$	5.0
Investor Partners	8.5
Total	$	13.5

Following the sale, this Partnership does not have a significant continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the statement of operations for all periods presented.

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

	Year Ended December 31,
Statement of Operations - Discontinued Operations	2013		2012
Revenues:
Crude oil, natural gas and NGLs sales	$	1,771,961	$	2,356,542
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	744,569		1,505,082
Direct costs - general and administrative expense	326,051		—
Depreciation, depletion and amortization	155,210		1,972,505
Accretion of asset retirement obligations	6,878		15,742
Impairment of crude oil and natural gas properties	—		2,191,002
Loss on sale of crude oil and natural gas properties	495,574		—
Total operating costs and expenses	1,728,282		5,684,331
Income (loss) from discontinued operations	$	43,679	$	(3,327,789	)

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

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Document Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 28, 2014	Jun. 30, 2013
Entity Information
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, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		0.00
Additional General Partnership Units Outstanding		0.00
Entity Well-Known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

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Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

Net Proved Reserves

This Partnership utilized the services of an independent petroleum engineer, Ryder Scott, to estimate this Partnership's 2013 and 2012 crude oil, natural gas and NGLs 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. This 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 crude oil, natural gas and NGLs expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development. As of December 31, 2013 and 2012, there are no proved undeveloped reserves for this Partnership.

This Partnership's estimated proved developed non-producing reserves consist entirely of reserves attributable to the Wattenberg Field's additional development. These additional development activities, part of the Additional Development Plan, generally occur five to ten years after initial well drilling. Funds of $3.1 million, which were provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners, were utilized for payment of additional development activities during 2012. Additional Development Plan activities are suspended until pipeline capacity improves. 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 following table presents the prices used to estimate this Partnership's reserves, by commodity:

	Price Used to Estimate Reserves (1)
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2013	$	81.91	$	3.38	$	23.14
2012	87.51		2.31		23.07

(1) The prices used to estimate reserves have been prepared in accordance with the SEC. 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 this 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 this Partnership's commodity derivatives.

The following table presents the changes in estimated quantities of this Partnership's reserves, all of which are located within the United States:

	Natural Gas		NGLs		Crude Oil and Condensate		Crude Oil Equivalent
	(MMcf)		(MBbl)		(MBbl)		(MBoe)
Proved Reserves:
Proved reserves, January 1, 2012	18,415		697		879		4,645
Revisions of previous estimates and reclassifications	(3,926	)	(81	)	34		(701	)
Production	(1,453	)	(21	)	(60	)	(323	)
Proved reserves, December 31, 2012 (1)	13,036		595		853		3,621
Revisions of previous estimates and reclassifications	(712	)	(74	)	(117	)	(310	)
Dispositions (1)	(6,874	)	—		(15	)	(1,161	)
Production	(734	)	(22	)	(53	)	(197	)
Proved reserves, December 31, 2013	4,716		499		668		1,953
Proved Developed Reserves, as of:
December 31, 2012	13,036		595		853		3,621
December 31, 2013	4,716		499		668		1,953

(1) Includes estimated reserve data related to this Partnership's Piceance Basin assets. In June 2013, this Partnership's Piceance Basin crude oil and natural gas properties were divested. See Note 11, Divestiture and Discontinued Operations, for additional information regarding this divestiture. As of December 31, 2012, total proved reserves related to this Partnership's Piceance Basin assets include 7,390 MMcf of natural gas and 17 MBbl of crude oil, for an aggregate of 1,249 MBoe of crude oil equivalent.

2013 Activity. As of December 31, 2013, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 310 MBoe. The revision includes downward revisions to previous estimates of 712 MMcf of natural gas, 74 MBbl of NGLs and 117 MBbl of crude oil. The downward revisions were the result of lower pricing, reduced asset performance and a reduction in proved non-producing reserves. There was a significant increase to the differential to NYMEX. A portion of non-producing reserves were reclassified from proved to probable due to not being economically producible. The outcome of these three items significantly decreased estimated reserves. The divestiture of this Partnership's Piceance Basin assets resulted in the disposition of reserves comprised of 6,874 MMcf of natural gas and 15 MBbl of crude oil. There were no proved undeveloped reserves developed in 2013. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2013.

2012 Activity. As of December 31, 2012, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 701 MBoe. The revision includes downward revisions to previous estimates of 3,926 MMcf of natural gas and 81 MBbls of NGLs, partially offset by an upward revision of 34 MBbls of crude oil. The downward revisions were the result of lower pricing and reduced asset performance. Proved undeveloped reserves of 268 MBoe were transferred to proved developed reserves in 2012 due to the reclassification of the Partnership's estimated Wattenberg behind pipe reserves as a result of the Managing General Partner's determination of the cost of a recompletion becoming less significant as compared to the cost of drilling a new well. There were no proved undeveloped reserves developed in 2012. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2012.

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

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

This Partnership is engaged solely in crude oil and natural gas activities, all of which are located in the continental United States. Drilling operations began upon funding in August 2007. This Partnership currently owns an undivided working interest in 75 gross (73.9 net) productive crude oil and natural gas wells located in the Wattenberg Field within the Denver-Julesburg Basin, north and east of Denver, Colorado.

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

	As of December 31,
	2013			2012 (1)
Leasehold costs	$	1,965,081		$	2,016,120
Development costs (2)	53,783,668			77,585,529
Crude oil and natural gas properties, successful efforts method, at cost	55,748,749			79,601,649
Less: Accumulated DD&A	(31,819,541		)	(38,868,788		)
Crude oil and natural gas properties, net	$	23,929,208		$	40,732,861

⁽¹⁾ Includes Piceance Basin crude oil and natural gas properties of $23,843,000, and related accumulated DD&A of $10,171,000, divested in 2013. See Note 11, Divestiture and Discontinued Operations, for further information.

⁽²⁾ Includes estimated costs associated with this Partnership's asset retirement obligations. See Note 6, Asset Retirement Obligations, for further information.

This Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of crude oil and natural gas or environmental protection. This Partnership also invests in equipment and services to complete refracturing or recompletion opportunities pursuant to the Additional Development Plan. There were no investments for this Partnership in 2013. Substantially all of the $3.2 million investment in 2012 is attributable to activities pursuant to the Additional Development Plan.

This Partnership recorded an impairment charge of $2,191,002 for the year ended December 31, 2012 associated with its Piceance Basin proved oil and natural gas properties. Accordingly, this Partnership reduced crude oil and natural gas properties by $3,820,877 and related accumulated depreciation, depletion and amortization for those properties by $1,629,875 as of December 31, 2012. See Note 10, Impairment of Capitalized Costs, for additional disclosure related to this Partnership's proved property impairment.

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Statements of Operations Statement (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Crude oil, natural gas and NGLs sales	$ 5,702,943	$ 5,904,716
Commodity price risk management gain (loss), net	(417,689)	1,078,580
Total revenues	5,285,254	6,983,296
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	1,395,391	1,304,676
Direct costs - general and administrative	209,500	200,972
Depreciation, depletion and amortization	3,121,340	3,466,521
Accretion of asset retirement obligations	68,266	63,165
Total operating costs and expenses	4,794,497	5,035,334
Income from continuing operations	490,757	1,947,962
Income (loss) from discontinued operations	43,679	(3,327,789)
Net income (loss)	534,436	(1,379,827)
Income from continuing operations	490,757	1,947,962
Less: Managing General Partner interest in net income	181,580	720,746
Net income allocated to Investor Partners	309,177	1,227,216
Net loss per Investor Partner unit, Continuing operations	$ 69	$ 275
Net loss per Investor Partner unit, Discontinued operations	$ 6	$ (469)
Net loss per Investor Partner unit	$ 75	$ (194)
Investor Partner units outstanding	4,470.00	4,470.00
Managing General Partner
Operating costs and expenses:
Income (loss) from discontinued operations	16,161	(1,231,282)
Limited Partner [Member]
Operating costs and expenses:
Income (loss) from discontinued operations	$ 27,518	$ (2,096,507)

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

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 this Partnership's working interest in crude oil and natural gas properties:

	Year ended December 31,
	2013			2012
Balance at beginning of period	$	1,110,093		$	1,031,186
Obligations discharged with divestiture of properties(1)	(249,424		)	—
Accretion expense	75,144			78,907
Balance at end of period	$	935,813		$	1,110,093

(1) This Partnership's asset retirement obligations relative to Piceance Basin assets were discharged with the sale of these assets during the year ended December 31, 2013. See Note 11, Divestiture and Discontinued Operations, for further information regarding the divestiture of the Piceance Basin assets.

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Concentration of Risk

12 Months Ended

Dec. 31, 2013

Risks and Uncertainties [Abstract]

Concentration Risk Disclosure [Text Block]

CONCENTRATION OF RISK

Accounts Receivable. This Partnership's accounts receivable are from purchasers of crude oil, natural gas and NGLs production. This Partnership sells substantially all of its crude oil, natural gas and NGLs to customers who purchase crude oil, natural gas and NGLs from other partnerships managed by this Partnership's Managing General Partner. Inherent to this Partnership's industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This industry concentration has the potential to impact this Partnership's overall exposure to credit risk in that its customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions.

As of December 31, 2013 and 2012, this 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 this 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 this Partnership's Managing General Partner, have experienced significant losses from uncollectible accounts receivable. This Partnership did not incur any losses on accounts receivable for the years ended December 31, 2013 and 2012. As of December 31, 2013, this Partnership had two customers representing 10% or more of the accounts receivable balance: Suncor Energy Marketing, Inc. and DCP Midstream, LP represented 76% and 22%, respectively.

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

	Year ended December 31,
Major Customer	2013	2012
Suncor Energy Marketing, Inc.	82%	84%
DCP Midstream, LP	18%	16%

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Asset Retirement Obligations Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

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

	Year ended December 31,
	2013			2012
Balance at beginning of period	$	1,110,093		$	1,031,186
Obligations discharged with divestiture of properties(1)	(249,424		)	—
Accretion expense	75,144			78,907
Balance at end of period	$	935,813		$	1,110,093

(1) This Partnership's asset retirement obligations relative to Piceance Basin assets were discharged with the sale of these assets during the year ended December 31, 2013. See Note 11, Divestiture and Discontinued Operations, for further information regarding the divestiture of the Piceance Basin assets.

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Use of Estimates, Policy [Policy Text Block]

The preparation of this Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires this Partnership to make estimates and assumptions that affect the amounts reported in this 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, NGLs and crude oil sales revenue, proved reserves, future cash flows from crude oil, natural gas and NGLs properties and valuation of derivative instruments

Basis of Accounting, Policy [Policy Text Block]

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

Cash and Cash Equivalents, Policy [Policy Text Block]

This Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. This Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution

Receivables, Policy [Policy Text Block]

accounts receivable are from purchasers of crude oil, natural gas and NGLs. This Partnership sells substantially all of its crude oil, natural gas and NGLs to customers who purchase crude oil, natural gas and NGLs from other partnerships managed by this 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

Inventory, Policy [Policy Text Block]

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

Derivatives, Policy [Policy Text Block]

All derivative assets and liabilities were recorded on the balance sheets at fair value. PDC, as Managing General Partner, elected not to designate any of this Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of this Partnership's derivative instruments were recorded in this Partnership's statements of operations and this Partnership's net income was subject to greater volatility than it would have been if this Partnership's derivative instruments had qualified for hedge accounting. The net settlements and the net change in fair value of unsettled derivatives are recorded in the line captioned, “Commodity price risk management gain, net.” As positions designated to this Partnership settled, positive and negative settlements were netted for distribution. Positive settlements were paid to this Partnership and negative settlements were deducted from this Partnership's cash distributions generated from production. This Partnership bore its proportionate share of counterparty risk. As of December 31, 2013, this Partnership had no outstanding derivative instruments.

The validation of the derivative instrument's fair value was performed by the Managing General Partner. While the Managing General Partner used common industry practices to develop this Partnership's valuation techniques, changes in this Partnership's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values

Oil and Gas Properties Policy [Policy Text Block]

This Partnership accounts for its crude oil and natural gas 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. This Partnership calculates quarterly DD&A expense by using estimated prior period-end reserves as the denominator, with the exception of this Partnership's fourth quarter where this Partnership uses the year-end reserve estimate adjusted to add back fourth quarter 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 Crude Oil, Natural Gas and NGLs Information - Unaudited,Net Proved Reserves, included at the end of these financial statements and accompanying notes elsewhere in this report for additional information regarding this Partnership's reserve reporting. In accordance with the Agreement, all capital contributed to this Partnership, after deducting syndication costs and a one-time management fee, was used solely for the drilling of crude oil and natural gas wells. This Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of crude oil, natural gas and NGLs 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 this Partnership's properties on a well-by-well basis as of December 31. Additionally, this Partnership adjusts reserves for major well rework or abandonment during the year, as needed. The process of estimating and evaluating crude oil, natural gas and NGLs 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 this 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 this Partnership's DD&A expense, a change in this Partnership's estimated reserves could have an effect on this Partnership's net income or loss.

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

this Partnership assesses its producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, 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 crude oil and natural gas. Certain events, including but not limited to, downward revisions in estimates to this 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 this Partnership's proved crude oil and natural gas 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 and is measured by the amount by which the net capitalized costs exceed their fair value. Impairment charges are included in the statement of operations line item impairment of crude oil and natural gas properties, with a corresponding reduction to crude oil and natural gas properties and accumulated depreciation, depletion and amortization line items on the balance sheet.

Production Tax Liability, Policy [Policy Text Block]

Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which this Partnership produces crude oil, natural gas and NGLs. This Partnership's share of these taxes recorded in the line crude oil, natural gas and NGLs production costs on this Partnership's statements of operations. This Partnership's production taxes payable are included in the caption accounts payable and accrued expenses on this Partnership's balance sheets.

Asset Retirement Obligations, Policy [Policy Text Block]

This 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 spud. Upon initial recognition of an asset retirement obligation, this 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, net of salvage value, 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 changes in retirement costs or the estimated timing of settling asset retirement obligations.

Revenue Recognition, Policy [Policy Text Block]

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. This Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of this Partnership's sales pursuant to which the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells this 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 this Partnership's purchasers and reflected in the wellhead price. The majority of this Partnership's natural gas and NGLs is sold by the Managing General Partner on a long-term basis, primarily over 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 and the quality of the natural gas.

Accounting Standards Recently Adopted [Policy Text Block]

Recent Accounting Standards

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

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Transactions with Managing General Partner

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

TRANSACTIONS WITH MANAGING GENERAL PARTNER

The Managing General Partner transacts business on behalf of this Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received by the Managing General Partner on behalf of this Partnership are distributed to the partners, net of corresponding operating costs and other cash outflows incurred on behalf of this Partnership. The fair value of this Partnership's portion of open derivative instruments were recorded on the December 31, 2012 balance sheet under the captions “Due from Managing General Partner-derivatives” in the case of a positive fair value of unsettled derivatives and “Due to Managing General Partner-derivatives” in the case of a negative fair value of unsettled derivatives. As of December 31, 2013, this Partnership had no outstanding derivative instruments.

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

	December 31, 2013			December 31, 2012
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	306,014		$	871,548
Net settlements of derivatives	—			356,531
Other (1)	(426,008		)	(427,481		)
Total Due (to) from Managing General Partner-other, net	$	(119,994	)	$	800,598

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

Commencing with March 2012 well operations, the Managing General Partner withholds from monthly Partnership cash available for distributions amounts to be used to fund statutorily-mandated well plugging, abandonment and environmental site restoration expenditures. A Partnership well may be sold or plugged, reclaimed and abandoned, with consent of all non-operators, when depleted or an evaluation is made that the well has become uneconomical to produce. Per-well plugging fees withheld during 2013 and 2012 were $50 per well each month the well produced. The total amount withheld from Partnership's cash available for distributions for the purposes of funding future Partnership obligations is recorded on the balance sheets in the long-term asset line captioned "Other assets." PDC plans to discontinue withholding these funds in early 2014 and will refund all funds withheld to the Partnership.

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 for the years ended December 31, 2013 and 2012. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the statements of operations for continuing operations or in Note 11, Divestiture and Discontinued Operations, for information on discontinued operations.    

	Year ended December 31,
	2013		2012
Well operations and maintenance (1)	$	1,660,093	$	2,260,438
Gathering, compression and processing fees (2)	119,017		339,542
Direct costs - general and administrative (3)	535,551		200,972
Refracturing and recompletion costs (4)	—		3,159,943
Cash distributions (5)	7,819,797		2,658,297

(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 this 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 this 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 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. 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 this 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 this Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between this 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 crude oil, natural gas and NGLs, such as:

• well tending, routine maintenance and adjustment;

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

• preparing production related reports to this 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; or

• 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 may enter into other transactions with this Partnership for services, supplies and equipment during the production phase of this 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 this 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, this 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, this Partnership pays the gathering fee charged by the third-party gathering the natural gas.

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

(4) Refracturing and recompletion costs relate to expenditures recorded pursuant to the Additional Development Plan.

(5) 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 the years ended December 31,2013 and 2012 include $100,277 and $17,636, respectively, related to equity cash distributions 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, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

Legal Proceedings

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

Environmental

Due to the nature of the oil and gas industry, this Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in this Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews. Liabilities for environmental remediation efforts are included in line item captioned “Accounts payable and accrued expenses” on the balance sheets.

During the year ended December 31, 2013, as a result of the Managing General Partner's periodic review, no new environmental remediation projects were identified and this Partnership's expense for environmental remediation efforts was not significant. This Partnership had no liabilities for environmental remediation efforts as of December 31, 2013. This Partnership's environmental remediation liabilities were approximately $5,000 as of December 31, 2012.

The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2013 which have not been provided for or would otherwise have a material impact on this 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 or other potential sources of liability will not be discovered on this Partnership's properties.

Royalty Matters

During the year ended December 31, 2013, this Partnership recognized charges totaling approximately $326,000 related to royalty payment disputes with interest owners in the Piceance Basin. These charges were included in Direct costs - general and administrative expenses within discontinued operations. The settlement charges were allocated to this Partnership based upon historical revenue amounts and were paid during 2013, thereby settling all current and future obligations related to this matter.

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Partners' Equity and Cash Distributions

12 Months Ended

Dec. 31, 2013

Equity [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 this Partnership. No publicmarket exists or will develop for the units. While units of this 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 described below.

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

			Managing
	Investor		General
	Partners		Partner
Partnership Revenue:
Crude oil, natural gas and NGLs 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:
Crude oil, natural gas and NGLs 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 this Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of this 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 this 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 this Partnership to be treated as a “publicly traded partnership” or result in the termination of this Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served 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,
	2013		2012
Cash distributions	$	20,863,568	$	7,136,923

Cash distributions increased in 2013 compared to 2012, primarily due to the July 2013 distribution of $13.5 million of the proceeds received for the Piceance Basin asset divestiture. See Note 11, Divestiture and Discontinued Operations, for additional details related to the divestiture of this Partnership's Piceance Basin assets.

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Impairment of Capitalized Costs

12 Months Ended

Dec. 31, 2013

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Impairment of crude oil and natural gas properties [Table Text Block]

IMPAIRMENT OF CRUDE OIL AND NATURAL GAS PROPERTIES

In December 2012, this Partnership recognized an impairment charge of approximately $2.2 million associated with its Piceance Basin proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on estimated future cash flows from unrelated third-party bids, a Level 3 input. See Supplemental Crude Oil, Natural Gas and NGLs Information–Unaudited–Capitalized Costs and Costs Incurred in Crude Oil and Natural Gas Property Development Activities for additional information on impairment of crude oil and natural gas properties.

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Asset Retirement Obligations Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Changes in Carrying Amounts of the Asset Retirement Obligation
Balance at beginning of year	$ 1,110,093		$ 1,031,186
Obligations discharged with divestiture of properties	(249,424)	[1]	0	[1]
Accretion expense	75,144		78,907
Balance at end of year	$ 935,813		$ 1,110,093

[1] This Partnership's asset retirement obligations relative to Piceance Basin assets were discharged with the sale of these assets during the year ended December 31, 2013. See Note 11, Divestiture and Discontinued Operations, for further information regarding the divestiture of the Piceance Basin assets.

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Derivative Financial Instruments Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

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

	Year ended December 31,
Statement of operations line item:	2013			2012
Commodity price risk management gain (loss), net
Net settlements	$	1,275,544		$	3,462,935
Net change in fair value of unsettled derivatives	(1,693,233		)	(2,384,355		)
Total commodity price risk management gain (loss), net	$	(417,689	)	$	1,078,580

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Transactions with Managing General Partner Transactions with Managing General Partner (Tables)

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Due from (to) Managing General Partner-other, net [Table Text Block]

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

	December 31, 2013			December 31, 2012
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	306,014		$	871,548
Net settlements of derivatives	—			356,531
Other (1)	(426,008		)	(427,481		)
Total Due (to) from Managing General Partner-other, net	$	(119,994	)	$	800,598

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

Schedule of Related Party Transactions [Table Text Block]

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 for the years ended December 31, 2013 and 2012. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the statements of operations for continuing operations or in Note 11, Divestiture and Discontinued Operations, for information on discontinued operations.    

	Year ended December 31,
	2013		2012
Well operations and maintenance (1)	$	1,660,093	$	2,260,438
Gathering, compression and processing fees (2)	119,017		339,542
Direct costs - general and administrative (3)	535,551		200,972
Refracturing and recompletion costs (4)	—		3,159,943
Cash distributions (5)	7,819,797		2,658,297

(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 this 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 this 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 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. 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 this 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 this Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between this 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 crude oil, natural gas and NGLs, such as:

• well tending, routine maintenance and adjustment;

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

• preparing production related reports to this 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; or

• 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 may enter into other transactions with this Partnership for services, supplies and equipment during the production phase of this 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 this 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, this 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, this Partnership pays the gathering fee charged by the third-party gathering the natural gas.

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

(4) Refracturing and recompletion costs relate to expenditures recorded pursuant to the Additional Development Plan.

(5) 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 the years ended December 31,2013 and 2012 include $100,277 and $17,636, respectively, related to equity cash distributions 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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Divestitures and Discontinued Operations Divestitures and Discontinued Operations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) from discontinued operations	$ 43,679	$ (3,327,789)
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Crude oil, natural gas and NGLs sales	1,771,961	2,356,542
Crude oil, natural gas and NGLs production costs	744,569	1,505,082
Direct costs - general and administrative expense	326,051	0
Depreciation, depletion and Amortization	155,210	1,972,505
Accretion of asset retirement obligations	6,878	15,742
Impairment of crude oil and natural gas properties	0	2,191,002
Loss on sale of crude oil and natural gas properties	495,574	0
Total operating costs and expenses	1,728,282	5,684,331
Income (loss) from discontinued operations	$ 43,679	$ (3,327,789)

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Statement of Partners' Equity Statement (USD $)	Total	Investor Partners	Managing General Partner
Balance at Dec. 31, 2011	$ 52,780,496	$ 38,445,661	$ 14,334,835
Change in Partners' Equity:
Distributions to Partners	(7,136,923)	(4,496,262)	(2,640,661)
Net income	(1,379,827)	(869,291)	(510,536)
Balance at Dec. 31, 2012	44,263,746	33,080,108	11,183,638
Change in Partners' Equity:
Distributions to Partners	(20,863,568)	(13,144,048)	(7,719,520)
Net income	534,436	336,695	197,741
Balance at Dec. 31, 2013	$ 23,934,614	$ 20,272,755	$ 3,661,859

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments Disclosure [Text Block]

DERIVATIVE FINANCIAL INSTRUMENTS

This Partnership's results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. Prior to June 30, 2013, to manage a portion of this Partnership's exposure to price volatility from producing crude oil and natural gas, the Managing General Partner utilized an economic hedging strategy for this Partnership's crude oil and natural gas sales in which PDC, as Managing General Partner, entered into derivative contracts on behalf of this Partnership to protect against price declines in future periods. While the Managing General Partner structured these derivatives to reduce this Partnership's exposure to changes in price associated with the derivative commodities, they also limited the benefit this Partnership might otherwise have received from price increases in the physical market. Partnership policy prohibited the use of crude oil and natural gas derivative instruments for speculative purposes. In June 2013, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated or sold to Caerus. Accordingly, as of December 31, 2013, this Partnership did not have any derivative instruments in place for its future production. Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production.

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

	Year ended December 31,
Statement of operations line item:	2013			2012
Commodity price risk management gain (loss), net
Net settlements	$	1,275,544		$	3,462,935
Net change in fair value of unsettled derivatives	(1,693,233		)	(2,384,355		)
Total commodity price risk management gain (loss), net	$	(417,689	)	$	1,078,580

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Divestitures and Discontinued Operations Divestitures and Discontiuned Operations (Tables)

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Distribution of Proceeds from Asset Divestiture [Table Text Block]

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture to the Managing General Partner and Investor Partners as follows:

	Amount
Distributed to:	(millions)
Managing General Partner	$	5.0
Investor Partners	8.5
Total	$	13.5

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

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

	Year Ended December 31,
Statement of Operations - Discontinued Operations	2013		2012
Revenues:
Crude oil, natural gas and NGLs sales	$	1,771,961	$	2,356,542
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	744,569		1,505,082
Direct costs - general and administrative expense	326,051		—
Depreciation, depletion and amortization	155,210		1,972,505
Accretion of asset retirement obligations	6,878		15,742
Impairment of crude oil and natural gas properties	—		2,191,002
Loss on sale of crude oil and natural gas properties	495,574		—
Total operating costs and expenses	1,728,282		5,684,331
Income (loss) from discontinued operations	$	43,679	$	(3,327,789	)

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Transactions with Managing General Partner Undistributed or Unsettled Transactions With Investor Partners (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Related Party Transaction [Line Items]
Plugging fees per well, per month	$ 50		$ 50
Due from (to) Managing General Partner-other, net	(119,994)		800,598
Crude oil, natural gas and NGLs sales revenues collected from the Partnership's third-party customers [Member]
Related Party Transaction [Line Items]
Due from (to) Managing General Partner-other, net	306,014		871,548
Net settlements on derivatives [Member]
Related Party Transaction [Line Items]
Due from (to) Managing General Partner-other, net	0		356,531
Other [Member]
Related Party Transaction [Line Items]
Due from (to) Managing General Partner-other, net	$ (426,008)	[1]	$ (427,481)	[1]

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

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Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

The following table presents this Partnership's derivative assets and liabilities that had been measured at fair value on a recurring basis:

	Balance Sheet	December 31, 2012
	Line Item	Level 2
Assets:
Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	4,409,574
Total assets		4,409,574
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	2,004,594
Total liabilities		2,004,594
Net asset		$	2,404,980