Rockies Region 2006 Limited Partnership 10-K 2012 FY Annual report

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, 2012

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 000-52787

Rockies Region 2006 Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia	20-5149573
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado  80203

(Address of principal executive offices)     (Zip code)

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

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

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

Title of Each Class

Limited Partnership Interests

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

As of February 28, 2013, this Partnership had 4,497.03 units of limited partnership interest and no units of additional general partnership interest outstanding.

Rockies Region 2006 Limited Partnership

2012 Annual Report on Form 10-K

Table of Contents

		Page
	Part I
Item 1	Business	3
Item 1A	Risk Factors	18
Item 1B	Unresolved Staff Comments	18
Item 2	Properties	18
Item 3	Legal Proceedings	18
Item 4	Mine Safety Disclosures	18
	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	21
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	32
Item 8	Financial Statements and Supplementary Data	32
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	32
Item 9A	Controls and Procedures	32
Item 9B	Other Information	33
	Part III
Item 10	Directors, Executive Officers and Corporate Governance	34
Item 11	Executive Compensation	38
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	38
Item 13	Certain Relationships and Related Transactions and Director Independence	39
Item 14	Principal Accountant Fees and Services	40
	Part IV
Item 15	Exhibits, Financial Statement Schedules	41
Signatures		44

PART I

WHERE YOU CAN FIND ADDITIONAL INFORMATION

The Rockies Region 2006 Limited Partnership (“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, or CIK, for this Partnership is 0001376912. 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

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

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

Btu - British thermal unit.

MBbl - One thousand barrels of crude oil or NGLs.

Mcf - One thousand cubic feet of natural gas volume.

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

MMBtu - One million British thermal units.

MMcf - One million cubic feet of natural gas volume.

MMcfe - One million cubic feet of natural gas equivalent.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Exchange Act 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 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 relate to, among other things: estimated natural gas, natural gas liquids ("NGLs") and crude oil reserves; additional development plans; the PDC-Sponsored Drilling Program Acquisition Plan as discussed in Item 1, Business, future production, expenses, cash flows and margins; anticipated capital expenditures; availability of additional midstream facilities and services in the Wattenberg Field and timing of that availability; the adequacy of this Partnership's insurance; the effectiveness of the Managing General Partner's derivative program in providing a degree of price stability; closing of and expected proceeds from this Partnership's pending asset disposition; 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 natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements.

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

• changes in production volumes and worldwide demand for natural gas, NGLs and oil, including economic conditions that might impact demand;

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

• impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement of 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 natural gas and crude oil 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 acquire supplies and services at reasonable prices;

• timing and receipt of necessary regulatory permits;

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

• this Partnership's future cash flows, liquidity and financial position;

• competition within the oil and gas industry;

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

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

• effect of derivative activities;

• 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;

• potential obstacles to completing this Partnership's pending asset disposition or other transactions, in a timely manner or at all, and purchase price or other adjustments relating to those transactions 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.

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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 natural gas, NGLs and crude oil. This Partnership was organized and began operations in 2006 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. PDC, the Managing General Partner, a Nevada corporation, owns the remaining 37% of this Partnership's capital, or equity interest. 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.

The Managing General Partner may repurchase Investor Partner units, under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner's limited partner unit repurchase program, as well as the current number of Investor Partners as of the date of filing, see Item 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. For information concerning the Managing General Partner's ownership interests in 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 continuing operations of its natural gas and crude oil 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, 2056, 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 other than those held by PDC or its affiliates, held by limited partners (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership (“Acquisition Plan”). For additional information regarding the Acquisition Plan, refer to disclosure included in PDC's prior filings made with the SEC and presentations on PDC's website. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement and such agreement will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnership units held by the non-affiliated investor partners of such limited partnership. Consummation of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and each non-affiliated investor partner will receive the right to receive a cash payment for their limited partnership units in that partnership and will no longer participate in that partnership's future earnings.

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.

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On December 21, 2011, PDC and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders related to 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. On June 15, 2012, the Court denied the motion. The Court has approved a litigation schedule including a jury trial in May 2014.

Business Strategy

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

This Partnership's business plan going forward, including the Additional Development Plan, is to produce and sell the natural gas, NGLs and crude oil 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 Partnership wells were "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 each well. All Partnership wells are 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, 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.

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

Areas of Operations

This Partnership's operating areas are profiled as follows:

Wattenberg Field, DJ Basin, Colorado. Located north and east of Denver, Colorado, this Partnership's wells in this field exhibit production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. Production in this field includes natural gas, NGLs and/or crude oil. This Partnership's 63 wells drilled in the Wattenberg Field that were completed to the Codell formation, 10 wells were also completed in the shallower Niobrara formation. Of this Partnership's development wells in this area are generally 7,000 to 8,000 feet in depth.

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Piceance Basin, Colorado. Located near the western border of Colorado, this Partnership's 23 wells in this field have also exhibited production histories typical for other wells located within this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. These wells generally produce natural gas along with small quantities of crude oil. The majority of this Partnership's development wells drilled in the area were drilled directionally from multi-well pads ranging from two to eight or more wells per drilling pad. The primary drilling targets were multiple sandstone reservoirs in the Mesa Verde formation and well depth ranges from 7,000 to 9,500 feet. Well spacing is approximately 10 acres per well.

On February 4, 2013, this Partnership's Managing General Partner, PDC, entered into a Purchase and Sale Agreement (“PSA”) with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership agreed to sell all of its Piceance Basin oil and gas properties for aggregate cash consideration of $7.8 million which is subject to customary post-closing adjustments to the purchase price, including adjustments based on title and environmental due diligence to be conducted by Caerus. Under the same PSA, PDC has agreed to sell to Caerus PDC's and PDC sponsored partnerships' Piceance Basin assets and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Based on the amounts allocated to this Partnership in the PSA, PDC determined that it was in the best interest of this Partnership to sell its Piceance Basis assets under the PSA. The PSA does not include any of this Partnership's Wattenberg Field assets. There can be no assurance that this transaction will close as planned. Additionally in 2013, PDC agreed to sell certain derivatives to Caerus of which this Partnership's share is $1.3 million. The Managing General Partner intends to use the proceeds from the sales for operational needs, for the Additional Development Plan or distributions to Partners. See Note 11, Subsequent Event, to this Partnership's financial statements included elsewhere in this report for additional details related to the planned divestiture.

Divestiture of North Dakota Assets. In December 2010, the Managing General Partner effected a letter of intent with an unrelated third-party which provided for the sale of this Partnership's North Dakota assets. The North Dakota assets were classified as held for sale as of December 31, 2010, and the results of operations related to those assets were reported as discontinued operations in the accompanying financial statements for the year ended December 31, 2011. In February 2011, the Managing General Partner executed a purchase and sale agreement on behalf of this Partnership and subsequently closed with the same unrelated party. This Partnership's proceeds from the sale were $5.7 million, resulting in a gain on sale of $3.3 million.

Title to Properties

This Partnership's leases are direct interests in producing properties. This Partnership believes it holds good and defensible title to its natural gas and crude oil properties, in accordance with standards generally accepted in the industry, through the record title held in 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

Natural Gas and Crude Oil Properties. This Partnership's properties consist of a working interest in the well bore in each well drilled by this Partnership. This Partnership drilled 97 wells (95.7 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 August 2007 when the last of this Partnership's 91 productive wells (89.7 net) were connected to sales and gathering lines. At that time, this Partnership's 91 productive wells included 86 gross (85.2 net) wells located in Colorado and five (4.5 net) wells located in North Dakota. One Wattenberg Field Codell formation well (1.0 net) and three Wattenberg Field D Sand and J Sand formations wells (3.0 net) drilled were evaluated as commercially unproductive and were, therefore, declared to be developmental and exploratory dry holes, respectively. Additionally, this Partnership participated in two North Dakota Nesson formation exploratory wells (2.0 net), one drilled in the Coteau Field and the second drilled in the Wildcat Field, which were determined to be commercially unproductive and, therefore, declared to be exploratory dry holes. The 97 wells discussed above are the only wells to be drilled by this Partnership since all of the funds raised in this Partnership's offering have been expended.

In February 2011, this Partnership's North Dakota assets were divested. See Note 10, Divestitures and Discontinued Operations, to this Partnership's financial statements included elsewhere in this report for additional details related to the divestiture of the North Dakota assets.

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Productive wells consist of producing wells and wells capable of producing natural gas and/or NGLs and crude oil in commercial quantities. The following table presents the number of this Partnership's productive wells by locationas of December 31, 2012 and 2011:

	Productive Natural Gas Wells
	2012		2011
Location	Gross	Net	Gross	Net
Piceance Basin	23.0	22.3	23.0	22.3
Wattenberg Field	63.0	62.9	63.0	62.9
Total Productive Wells	86.0	85.2	86.0	85.2

Additional Development Plan. The Managing General Partner has begun executing a plan for this Partnership's Wattenberg Field wells, which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “Additional Development Plan”). The Additional Development Plan consists of this Partnership's refracturing of wells currently producing in the Codell formation and/or recompletion 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.

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, the production resulting from 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 this 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.

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

Current estimated costs for these well refracturings or recompletions are between $180,000 and $260,000 per activity. As of December 31, 2012, this Partnership has approximately 108 additional development opportunities remaining. Total withholding for these activities from this Partnership's cash available for distributions is estimated to be between $19.9 million and $22.2 million if all of the activities are performed. As of December 31, 2012, eight of the originally estimated 116 additional development opportunities have been completed. 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. As of December 31, 2012, $1,648,000 of the $1,720,000 funds

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previously withheld from this Partnership's cash distributions pursuant to the Additional Development Plan were used to pay the Managing General Partner for the cost of eight recompletions and/or refracturings on four of this Partnership's wells and for major repair projects.

This Partnership, along with other operators in the Wattenberg Field, has recently experienced extremely high line pressures due to an oversupply of natural gas and NGLs in the field based upon the main pipeline/processing provider's current take away capacity and hot weather. The result of the high line pressure is that many of the wells in this field, including this Partnership's wells, have had their production curtailed and the curtailments have reduced the amount of natural gas, crude oil and NGLs produced and sold over the last several months. When natural gas production is curtailed, the curtailment affects the well's ability to lift the liquids out of the well bore.

DCP Midstream LP (“DCP”), an independent midstream company, is the main purchaser of natural gas and NGLs in this field. The Managing General Partner is working closely with DCP, which is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity in the Wattenberg Field. However, the Managing General Partner does not expect the impact of this increased capacity to substantially benefit this Partnership until late 2013.

Due to the limitations in the take away capacity and the extended timeline anticipated for the curtailments, the projected rates of return for refracturing and recompletion activities have significantly deteriorated. Therefore, at this time, PDC has temporarily suspended the Additional Development Plan and the withholding of funds designated for this development until the high line pressure situation improves. Unspent funds of $72,000 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 the second half of 2013. However, no assurance can be given that the Additional Development Plan will recommence.

Proved Reserves

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

All of this Partnership's proved reserves are located onshore in the United States. This Partnership's reserve estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and subsequent SEC staff regulations, interpretations and guidance. As of December 31, 2012, all of this Partnership's proved reserves have been estimated by independent petroleum engineers.

The Managing General Partner has established a comprehensive process that governs the determination and reporting of 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 PDC reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data as well as production performance data. The 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 an independent engineering firm engaged to estimate this Partnership's reserves.

This Partnership's reserve estimates as of December 31, 2012 and 2011 were based on reserve reports prepared by Ryder Scott Company, L.P. ("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 by acceptable industry methods and to a level of detail the Managing General Partner deems appropriate. Ryder Scott's final estimated reserve report was reviewed and approved by the Managing General Partner's engineering staff and management.

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The professional qualifications of the Managing General Partner's internal lead engineer primarily responsible for overseeing the preparation of this Partnership's reserve estimate meets the standards of Reserves Estimator as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This Managing General Partner employee holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering and has over 35 years of experience in reservoir engineering. The individual is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and is a registered Professional Engineer in the State of Colorado.

Proved reserves are those quantities of natural gas, NGLs and crude oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing 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. This Partnership's category of proved reserves is proved developed reserves. Proved developed reserves are quantities of natural gas, NGLs and crude oil expected to be recovered through existing wells with existing equipment and operating methods.

The SEC's reserve rules 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 has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

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.

Reserves estimates involve judgments and, therefore, cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance data, new geological and geophysical data and economic changes. This Partnership's estimated proved developed non-producing reserves consist entirely of reserves attributable to the Wattenberg Field's additional development opportunities. See Item 1, Business−Operations - Drilling and Other Activities-Additional Development Plan. For additional information regarding this Partnership's reserves, see the Net Proved Reserves section of the Supplemental Information provided with the financial statements included elsewhere in this report. There were no proved undeveloped reserves that were developed in 2012. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2012.

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

	As of December 31,
	2012	2011
Proved Reserves
Natural Gas (MMcf)	6,560	9,894
Crude Oil and Condensate (MBbl)	491	553
NGLs (MBbl)	346	416
Total proved reserves (MMcfe)	11,582	15,708

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

	As of December 31, 2012
			Crude Oil and	Natural Gas
	Natural Gas	NGLs	Condensate	Equivalent
	(MMcf)	(MBbl)	(MBbl)	(MMcfe)	Percent
Proved reserves
Piceance Basin(1)	3,378	—	4	3,402	29	%
Wattenberg Field	3,182	346	487	8,180	71	%
Total proved reserves	6,560	346	491	11,582	100	%
	As of December 31, 2011
			Crude Oil and	Natural Gas
	Natural Gas	NGLs	Condensate	Equivalent
	(MMcf)	(MBbl)	(MBbl)	(MMcfe)	Percent
Proved reserves
Piceance Basin	6,154	—	8	6,202	39	%
Wattenberg Field	3,740	416	545	9,506	61	%
Total proved reserves	9,894	416	553	15,708	100	%

(1) Represents estimated reserve data related to this Partnership's Piceance Basin assets, which are to be divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 11, Subsequent Event, to this Partnership's financial statements included elsewhere in this report for additional details related to the planned divestiture of this Partnership's Piceance Basin assets. There can be no assurance that this transaction will close as planned.

Production, Sales, Prices and Lifting Costs - By Field

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

	Year ended December 31,
	2012	2011
Production (1)
Natural gas (Mcf)
Piceance Basin (2)	745,057	853,374
Wattenberg Field	90,986	119,967
Total Natural Gas	836,043	973,341
Crude Oil (Bbl)
Piceance Basin (2)	1,350	1,119
Wattenberg Field	25,680	32,139
Total Crude Oil	27,030	33,258
NGLs (Bbl)
Wattenberg Field	9,847	12,373
Natural gas equivalent (Mcfe)
Piceance Basin (2)	753,157	860,088
Wattenberg Field	304,148	387,039
Total natural gas equivalent	1,057,305	1,247,127

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Natural Gas, NGLs and Crude Oil Sales
Natural gas sales
Piceance Basin (2)	$	1,325,662	$	2,502,055
Wattenberg Field	202,491		368,662
Total natural gas sales	1,528,153		2,870,717
Crude oil sales
Piceance Basin (2)	108,727		87,659
Wattenberg Field	2,238,343		2,879,104
Total crude oil sales	2,347,070		2,966,763
NGLs sales
Wattenberg Field	253,747		463,272
Natural gas, NGLs and crude oil sales
Piceance Basin (2)	1,434,389		2,589,714
Wattenberg Field	2,694,581		3,711,038
Total natural gas, NGLs and crude oil sales	$	4,128,970	$	6,300,752
Average Sales Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)
Piceance Basin (2)	$	1.78	$	2.93
Wattenberg Field	2.23		3.07
Average sales price natural gas, both fields	1.83		2.95
Crude Oil (per Bbl)
Piceance Basin (2)	$	80.54	$	78.34
Wattenberg Field	87.16		89.58
Average sales price crude oil, both fields	86.83		89.20
NGLs (per Bbl)
Wattenberg Field	$	25.77	$	37.44
Natural gas equivalent (per Mcfe)
Piceance Basin (2)	$	1.90	$	3.01
Wattenberg Field	8.86		9.59
Average sales price natural gas equivalents, both fields	3.91		5.05
Average Production (Lifting) Cost (per Mcfe) (3)
Piceance Basin (2)	$	2.16	$	2.14
Wattenberg Field	2.51		2.28
Average production cost, both fields	2.26		2.18

(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) On February 4, 2013, the Managing General Partner entered into a purchase and sale agreement pursuant to which this Partnership has agreed to sell this Partnership's Piceance Basin oil and gas properties. There can be no assurance that this transaction will close as planned. See Note 11, Subsequent Event, to this Partnership's financial statements included elsewhere in this report for additional information regarding the planned divestiture.

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

10

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.

Natural Gas, NGLs and Crude Oil Sales

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

• 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 indexed or NYMEX monthly pricing provisions with the remaining production sold under contracts with daily pricing provisions. Virtually all of this Partnership's contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on whether a well delivers to a gathering or transmission line and quality of the natural gas. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, this Partnership's revenues from the sale of natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline. The Managing General Partner believes that the pricing provisions of this Partnership's natural gas contracts are customary in the industry.

• NGLs. The majority of this Partnership's NGLs are sold to one NGLs marketer in the Wattenberg Field. This Partnership's NGLs production is sold under both short- and long-term purchase contracts with monthly pricing provisions based on an average daily price.

• Crude oil. This Partnership does not refine any of its crude oil production. This Partnership sells its crude oil to oil marketers and refiners. This Partnership's crude oil production is sold to purchasers at or near this Partnership's wells under both short- and long-term purchase contracts with monthly pricing provisions based on an average daily price.

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 expenses to move this Partnership's natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based upon the volume and distance shipped, as well as the fee charged by the third-party processor or transporter. 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. While the Managing General Partner's ability to market this Partnership's volumes of natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, this Partnership's production and cash flows from the affected properties could be adversely affected.

This Partnership's 2012 production was adversely affected by high line pressures due to an oversupply of natural gas and NGLs in the Wattenberg Field based upon the main pipeline/processing provider's current take away capacity and hot weather. The result of the high line pressure is that many of the wells in this field, including this Partnership's wells, have had their production curtailed and the curtailments have reduced the amount of natural gas, crude oil and NGLs produced and sold over the last several months. When natural gas production is curtailed, the curtailment affects the well's ability to lift the liquids out of the well bore. The Managing General Partner is working closely with the main purchaser of natural gas and NGLs in this field, DCP, which is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity in the Wattenberg Field. However, the Managing General Partner does not expect the impact of this increased capacity to substantially benefit this Partnership until late 2013. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition - Recent Developments, for further information of the impact of these curtailments on this Partnership.

In certain instances, the Managing General Partner enters into firm transportation agreements when selling a portion of this Partnership's natural gas volumes. In order to meet pipeline specifications, the Managing General Partner is required, in some cases, to process this Partnership's natural gas before it can be transported. The Managing General Partner typically contracts with third parties in the Piceance Basin area of the Rocky Mountain Region for firm transportation of this Partnership's natural gas.

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

11

Delivery Commitments

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

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

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

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

See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Summary Operating Results, for production, sales, prices and production cost data for years ended December 31, 2012 and 2011.

Commodity Price Risk Management Activities

The Managing General Partner, on behalf of this Partnership in accordance with the D&O Agreement, utilizes commodity based derivative instruments to manage a portion of this Partnership's exposure to price volatility with regard to this Partnership's natural gas and crude oil sales. The financial instruments generally consist of collars, swaps and basis swaps and are NYMEX-traded and Colorado Interstate Gas ("CIG") based contracts. The Managing General Partner may utilize derivatives based on other indices or markets where appropriate. The contracts provide a degree of price stability for committed and anticipated natural gas and crude oil 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 manages price risk on only a portion of this Partnership's anticipated production, so the remaining portion of this Partnership's production is subject to the full fluctuation of market pricing.

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

This Partnership is subject to price fluctuations for natural gas and crude oil sold in the spot market and under market index contracts. Currently, the Managing General Partner does not anticipate entering into additional commodity based derivative instruments on behalf of this Partnership. In addition, the Managing General Partner may close out any portion of derivatives that may exist from time to time which may result in a realized gain or loss on that derivative transaction. 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 derivatives gains or losses for years ended December 31, 2012 and 2011.

Governmental Regulation

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

12

Regulation of Natural Gas and Crude Oil Production. This Partnership's production business is subject to various federal, state and local laws and regulations on the taxation of natural gas and crude oil, the development, production and marketing of natural gas and crude oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing 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. As a result, the Managing General Partner is unable to predict the future cost or effect of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas. 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") 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 its 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 and NGLs sales. Competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently the Managing General Partner has seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in-gas, which could adversely affect cash flows from the affected area.

Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. The industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. The Managing General Partner cannot determine to what extent 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 interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and restrictive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken restricting drilling or imposing environmental protection requirements resulting in increased costs, this Partnership's business and prospects may be adversely affected.

13

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 natural gas and/or crude oil 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 recently asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA"), and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

Colorado has adopted regulations that could impose more stringent permitting, transparency and well construction requirements on hydraulic fracturing operations. In December 2011, Colorado adopted a fracturing chemical disclosure rule wherein all chemicals used in the hydraulic fracturing of a well must be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission. The new rules also require operators seeking new location approvals to provide certain disclosures regarding fracturing to surface owners and adjacent property owners within 500 feet of a new well. In December 2012 and February 2013, Colorado finalized a baseline groundwater sampling rule and a new rule governing setback distances of oil and gas wells located near population centers.

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

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, the City of Fort Collins, Colorado, adopted on February 19, 2013 a ban on drilling and fracturing of new wells within city limits. If new laws or regulations that significantly restrict hydraulic fracturing or well locations are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude this Partnership's ability to execute the Additional Development Plan. If hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, this Partnership's fracturing activities could become subject to additional permitting requirements that could 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.

This Partnership currently owns properties that for many years have been used for the exploration and production of natural gas and crude oil. 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 have operated prior to the enactment of applicable laws now governing these areas, or 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 natural gas and crude oil 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.

14

CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. As an owner and operator of natural gas and crude oil wells, 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. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from this Partnership's operations. The EPA and states have been developing 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 recordkeeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. The New Source Performance Standards regarding oil and gas operations ("NSPS 0000") introduced by the EPA in 2011 became effective in 2012, adding administrative and operational costs. Colorado partially adopted the requirements of NSPS 0000 in 2012 and will consider full adoption in 2013.

The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction where construction will disturb wetlands or other waters of the United States. The CWA also regulates storm water run-off from natural gas and crude oil facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, 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.

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 2013 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 drilling and 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 natural gas and crude oil companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing natural gas and crude oil. 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 natural gas and crude oil exploration.

15

Recently, certain regions experienced strong demand for drilling services and supplies, which resulted in increasing costs. This Partnership has experienced intense competition for drilling and pumping services in the Wattenberg Field. 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 position, 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.

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 natural gas and crude oil 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 natural gas, NGLs and crude oil produced from this Partnership's wells. This Partnership designated PDC as its natural gas, NGLs and crude oil 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 natural gas, NGLs and crude oil. 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.

16

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, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of natural gas and crude oil. 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 worker's compensation, operator's bodily injury liability and property damage liability insurance, employer's liability insurance, automobile public liability insurance and operator's umbrella liability insurance and intends to maintain these policies subject to PDC's analysis of their premium costs, coverage and other factors. During drilling operations, the Managing General Partner maintained public liability insurance of not less than $10 million; however, PDC may at its sole discretion 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.

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.

Customers. PDC markets the natural gas, NGLs and crude oil from Partnership wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of this Partnership. Currently, PDC sells Partnership natural gas in the Piceance Basin to WPX Energy Rocky Mountain, LLC ("WPX"), which has an extensive gathering and transportation system in this Basin. In the Wattenberg Field, the natural gas and NGLs are sold primarily to DCP, which gathers and processes the gas and liquefiable hydrocarbons produced. Natural gas and NGLs produced in Colorado may be impacted by changes in market prices on a national level, as well as changes in the market for natural gas within the Rocky Mountain Region. Sales of natural gas and NGLs from this Partnership's wells to DCP and WPX are made on the spot market via open-access transportation arrangements through WPX or other 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, primarily as feedstock for refineries currently owned by Suncor Energy Marketing, Inc., which are located north of Denver, Colorado. Oil prices fluctuate not only with the general market for oil as may be indicated by changes in the New York Mercantile Exchange ("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.

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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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PART II

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

AND ISSUER PURCHASES OF EQUITY SECURITIES

At December 31, 2012, this Partnership had 2,007 Investor Partners holding 4,497.03 units and one Managing General Partner. The investments held by the Investor Partners are in the form of limited partnership interests. Investor Partners' interests are transferable; however, no assignee of units in this Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. As of December 31, 2012, the Managing General Partner has repurchased 56.3 units of Partnership interests from Investor Partners.

Market. There is no public market for this Partnership units, nor will a public market develop for these units in the future. Investor Partners may not be able to sell their Partnership interests or may only be able to sell their Partnership interest for less than fair market value. No transfer of a unit may be made unless the transferee satisfies relevant suitability requirements, as imposed by federal and state law or this Partnership 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

19

from this Partnership without any corresponding distributions in future years. If PDC were to be successful in the future acquisition effort of this Partnership, liquidation of this Partnership and a final payout 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. For additional information regarding PDC's disclosed partnership acquisition intentions, refer to Item 1, Business - PDC Sponsored Drilling Program Acquisition Plan.

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

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

	Cash
Period	Distributions
For the year ended December 31, 2012	$	3,376,833
For the year ended December 31, 2011	8,613,429
For the period from this Partnership's inception to December 31, 2012	$	82,803,344

The decrease in distributions for the year ended December 31, 2012 as compared to 2011 is primarily due to this Partnership's distribution of approximately $4.7 million of the proceeds from the sale of the North Dakota assets to the Investor Partners and Managing General Partner in 2011 and by a decrease in cash flows from operating activities during 2012, partially offset by higher withholdings in 2011 pursuant to the Additional Development Plan. For additional information, see Drilling and Other Development Activities − Additional Development Plan above.

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 natural gas, NGLs and crude oil production, or significant increases in the production of natural gas, NGLs and crude oil from the successful additional development of these properties, if any. The funds necessary for any additional development would be withheld from 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.

20

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-serve 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, 2012:

Period	Total Number of  Units Repurchased	Average Price Paid  Per Unit
October 1 - 31, 2012	1.08	$	1,702
November 1 - 30, 2012	1.00	1,695
December 1 - 31, 2012	3.00	1,615
Total	5.08	$	1,649

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS

OF OPERATIONS

The following discussion and analysis, as well as other sections in this 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 included in this report.

Partnership Overview

Rockies Region 2006 Limited Partnership engages in the development, production and sale of natural gas, NGLs and crude oil. This Partnership began natural gas and crude oil operations in September 2006 and operates 86 gross (85.2 net) productive wells located in the Rocky Mountain Region of Colorado. This Partnership has drilled four additional wells determined to be dry holes, consisting of one developmental dry hole and three exploratory dry holes in the Wattenberg Field in Colorado. This Partnership drilled five (4.5 net) producing wells in North Dakota and two exploratory dry holes in North Dakota. In February 2011, this Partnership sold its North Dakota assets. The Managing General Partner markets this Partnership's natural gas and crude oil production to midstream marketers. Natural gas, NGLs and crude oil is 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 natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. 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. Seasonal factors, such as effects of weather on prices received, costs incurred and availability of PDC or third-party owned pipeline capacity, due to 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.

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Recent Developments

Additional Development Plan

This Partnership, along with other operators in the Wattenberg Field, has recently experienced high line pressures due to an oversupply of natural gas and NGLs in the field based upon the main pipeline/processing provider's current take away capacity and hot weather. The result of the high line pressure is that many of the wells in this field, including this Partnership's wells, have had their production curtailed and the curtailments have reduced the amount of natural gas, crude oil and NGLs produced and sold over the last several months. When natural gas production is curtailed, the curtailment affects the well's ability to lift the liquids out of the well bore.

DCP, an independent midstream company, is the main purchaser of natural gas and NGLs in the Wattenberg Field. The Managing General Partner is working closely with DCP, which is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity in the Wattenberg Field. However, the Managing General Partner does not expect the impact of this increased capacity to substantially benefit this Partnership until late 2013.

Due to the limitations in the take away capacity and the extended timeline anticipated for the curtailments, the projected rates of return for refracturing and recompletion activities have significantly deteriorated. Therefore, at this time, PDC has temporarily suspended the Additional Development Plan and the withholding of funds designated for this development until the high line pressure situation improves. Unspent funds of $72,000 previously withheld pursuant to the Additional Development Plan were distributed during the fourth quarter of 2012 based upon each Investor Partner's proportionate ownership interest. It is currently anticipated that withholding will recommence sometime in the second half of 2013. However, no assurance can be given that the Additional Development Plan will recommence. See Item 1, Business−Operations - Drilling and Other Development Activities-Additional Development Plan.

2013 Planned Divestiture

On February 4, 2013, this Partnership's Managing General Partner, PDC, entered into a Purchase and Sale Agreement (“PSA”) with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership agreed to sell all of its Piceance Basin oil and gas properties for aggregate cash consideration of $7.8 million which is subject to customary post-closing adjustments to the purchase price, including adjustments based on title and environmental due diligence to be conducted by Caerus. Under the same PSA, PDC has agreed to sell to Caerus PDC's and PDC sponsored partnerships' Piceance Basin assets and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Based on the amounts allocated to this Partnership in the PSA, PDC determined that it was in the best interest of this Partnership to sell its Piceance Basis assets under the PSA. The PSA does not include any of this Partnership's Wattenberg Field assets. There can be no assurance that this transaction will close as planned. Additionally in 2013, PDC agreed to sell certain derivatives to Caerus of which this Partnership's share is $1.3 million. The Managing General Partner intends to use the proceeds from the sales for operational needs, for the Additional Development Plan or distributions to Partners. See Note 11, Subsequent Event, to this Partnership's financial statements included elsewhere in this report for additional details related to the planned divestiture.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 34%, or $2.2 million, for the year ended December 31, 2012 compared to the year ended December 31,2011, while production volumes declined 15% year-to-year. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $3.91 for the current year compared to $5.05 for 2011. Realized derivative gains from natural gas sales contributed an additional $1.98 per Mcfe, or $2.1 million, to the total revenues for the year ended December 31, 2012 compared to an additional $0.42 per Mcfe, or $0.5 million, from natural gas and crude oil sales for the year ended December 31,2011. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, increased to $5.89 for the year ended December 31, 2012 from $5.47 for 2011.

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Results of Operations

Summary Operating Results

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

	Year ended December 31,
	2012		2011			Change
Number of gross producing wells (end of period)	86		86			—
Production(1)
Natural gas (Mcf)	836,043		973,341			(14	)%
NGLs (Bbl)	9,847		12,373			(20	)%
Crude oil (Bbl)	27,030		33,258			(19	)%
Natural gas equivalents (Mcfe)(2)	1,057,305		1,247,127			(15	)%
Average Mcfe per day	2,897		3,417			(15	)%
Natural gas, NGLs and crude oil sales
Natural gas	$	1,528,153	$	2,870,717		(47	)%
NGLs	253,747		463,272			(45	)%
Crude oil	2,347,070		2,966,763			(21	)%
Total natural gas, NGLs and crude oil sales	$	4,128,970	$	6,300,752		(34	)%
Realized gain (loss) on derivatives, net
Natural gas	$	2,096,348	$	997,532		110	%
Crude oil	—		(476,510		)	(100	)%
Total realized gain on derivatives, net	$	2,096,348	$	521,022		*
Average selling price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	1.83	$	2.95		(38	)%
NGLs (per Bbl)	25.77		37.44			(31	)%
Crude oil (per Bbl)	86.83		89.20			(3	)%
Natural gas equivalents (per Mcfe)	3.91		5.05			(23	)%
Average selling price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	4.34	$	3.97		9	%
NGLs (per Bbl)	25.77		37.44			(31	)%
Crude oil (per Bbl)	86.83		74.88			16	%
Natural gas equivalents (per Mcfe)	5.89		5.47			8	%
Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)	$	2.33	$	2.47		(6	)%
Depreciation, depletion and amortization	2.96		2.38			24	%
Operating costs and expenses
Direct costs - general and administrative	$	203,789	$	219,784		(7	)%
Depreciation, depletion and amortization	3,125,736		2,969,780			5	%
Cash distributions	$	3,376,833	$	8,613,429		(61	)%

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

Amounts may not recalculate due to rounding.

_______________

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

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

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

Natural Gas, NGLs and Crude Oil Sales

Changes in Natural Gas, NGLs and Crude Oil Sales Volumes. For the 2012annual period compared to the 2011annual period, natural gas, NGLs and crude oil production, on an energy equivalency-basis, decreased 15% primarily due to normal production declines for this stage in the wells’ production life cycle and a decrease in production precipitated by curtailments due to high line pressure in the Wattenberg Field, partially offset by increased production from wells refractured or recompleted in accordance with the Additional Development Plan.

Changes in Natural Gas Sales. The $1.3 million, or 47%, decrease in natural gas sales for the 2012annual period as compared to the 2011annual period, was a reflection of a production volume decrease of 14% and by a lower average sales price per Mcf of 38%. The average sales price per Mcf, excluding the impact of realized derivative gains, was $1.83 for the current year annual period compared to $2.95 for the same period a year ago.

Changes in NGLs Sales. The $0.2 million, or 45%, decrease in NGLs sales for the 2012annual period as compared to the 2011annual period, was primarily a reflection of a production volume decrease of 20%, and by a lower average sales price per Bbl of 31%. The average sales price per Bbl, excluding the impact of realized derivative gains, was $25.77 for the current year annual period compared to $37.44 for the same period a year ago.

Changes in Crude Oil Sales. The $0.6 million, or 21%, decrease in crude oil sales for the 2012annual period as compared to the 2011annual period, was primarily a reflection of a production volume decrease of 19%, and by a lower average sales price per Bbl of 3%. The average sales price per Bbl, excluding the impact of realized derivative gains, was $86.83 for the current year annual period compared to $89.20 for the same period a year ago.

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

Natural gas prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. Increased drilling activity and curtailments due to limited capacity on local gathering and processing infrastructure, combined with hot weather, resulted in capacity constraints during the second and third quarters of 2012. Like most producers, this Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond this Partnership's control. The price this Partnership receives for its natural gas is impacted by the Managing General Partner's transportation, gathering and processing agreements. This Partnership currently uses the "net-back" method of accounting for these arrangements related to its natural gas sales. This Partnership sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

The price this Partnership receives for its natural gas produced is based on a market basket of prices, which generally includes natural gas sold at, near or below Colorado Interstate Gas ("CIG") prices, as well as other nearby regional prices. This Partnership has experienced a decline in the price of NGLs, mainly at Conway hub in Kansas where this Partnership's Wattenberg production is marketed. This is primarily due to the increase in ethane and propane volumes flowing to Conway, with a limited market for these products out of the area. Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics. The majority of this Partnership's crude oil is sold on a calendar-year basis at a fixed differential to NYMEX pricing.

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Commodity Price Risk Management

This Partnership used various derivative instruments to manage fluctuations in natural gas and crude oil prices. This Partnership had in place collars, fixed-price swaps and/or basis swaps on a portion of this Partnership's estimated natural gas and crude oil production. This Partnership sold its natural gas and crude oil 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 ultimately realized a price related to its collars of no less than the floor and no more than the ceiling and, for this Partnership's commodity swaps, this Partnership ultimately realized the fixed price related to its swaps.

Commodity price risk management includes realized gains and losses and unrealized mark-to-market changes in the fair value of the derivative instruments related to this Partnership's natural gas and crude oil 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.

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

	Year ended December 31,
	2012			2011
Commodity price risk management gain, net:
Realized gains (losses)
Natural gas	$	2,096,348		$	997,532
Crude oil	—			(476,510		)
Total realized gains, net	2,096,348			521,022
Unrealized gains (losses)
Reclassification of realized gains included in
prior periods unrealized gains	(1,725,276		)	(284,236		)
Unrealized gains for the period	286,820			2,230,069
Total unrealized gains (losses), net	(1,438,456		)	1,945,833
Total commodity price risk management gain, net	$	657,892		$	2,466,855

Realized gains of $2.1 million recognized in the year ended December 31, 2012 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. As of December 31, 2012, realized gains on natural gas, exclusive of basis swaps, were $3.5 million. These gains were offset in part by realized losses of $1.4 million on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

Unrealized gains of $0.3 million for the year ended December 31, 2012 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of this Partnership's open positions, offset in part by the narrowing of the CIG basis forward curve. For the year ended December 31, 2012, unrealized gains on this Partnership's natural gas positions were $0.3 million, partially offset by unrealized losses on this Partnership's CIG basis swaps.

Realized gains recognized in 2011 were primarily the result of lower natural gas prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. Realized gains on natural gas, exclusive of basis swaps, were $2.4 million, reflective of a higher weighted-average strike price compared to the weighted-average settlement price. These gains were offset in part by realized losses of $1.4 million on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps. The net realized gains on natural gas derivative positions in 2011 were offset in part by realized losses of $0.5 million on this Partnership's crude oil positions as a result of higher prices at settlement compared to the respective strike price of this Partnership's derivative positions.

25

Unrealized gains in 2011 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of this Partnership's open positions, offset in part by the narrowing of the CIG basis forward curve. During 2011, unrealized gains on this Partnership's natural gas positions were $2.5 million, offset in part by unrealized losses on this Partnership's CIG basis swaps of $0.3 million.

The following table presents this Partnership's derivative positions in effect as of December 31, 2012:

	Fixed-Price Swaps			CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-MMBtu(1))	Weighted- Average Contract Price		Quantity (Gas-MMBtu(1))	Weighted- Average Contract Price			Fair Value at December 31, 2012(2)
Natural Gas
NYMEX
01/01 - 03/31/2013	194,887	$	7.12	194,887	$	(1.88	)	$	402,922
04/01 - 06/30/2013	192,755	7.12		192,755	(1.88		)	399,696
07/01 - 09/30/2013	190,145	7.12		190,145	(1.88		)	366,386
10/01 - 12/31/2013	185,282	7.12		185,282	(1.88		)	312,278
Total(3)	763,069			763,069				$	1,481,282

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

⁽²⁾ As of December 31, 2012, none of the fair value of this Partnership's derivative assets were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value of Financial Instruments, to this Partnership's financial statements included elsewhere in this report.

⁽³⁾ Pursuant to a purchase and sale agreement entered into on February 4, 2013, approximately 654,455 MMBtu of Fixed-Price Swaps and an equal amount of CIG Basis Protection Swaps will be assigned to certain affiliates of Caerus upon the closing of the planned sale. There can be no assurance that this transaction will close as planned. See Note 11, Subsequent Event, to this Partnership's financial statements included elsewhere in this report for additional information regarding the planned divestiture of certain of this Partnership's natural gas properties.

Natural Gas, NGLs and Crude Oil Production Costs

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

Changes in natural gas, NGLs and crude oil production expenses. Natural gas, NGLs and crude oil production costs for the year ended December 31, 2012 decreased by $0.6 million compared to the same period in 2011. Lease operating costs were lower by $0.3 million in 2012 as workovers, tubing repairs and non-recurring environmental remediation activities were collectively higher in 2011. Production taxes decreased by $0.3 million in 2012, consistent with sales declines from 2011. Natural gas, NGLs and crude oil production costs per Mcfe decreased to $2.33 during 2012 from $2.47 in 2011 due to a 20% reduction in costs partially offset by a 15% reduction in production volume.

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Depreciation, Depletion and Amortization ("DD&A")

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

Changes in DD&A expense. DD&A expense increased approximately $156,000 for the year ended December 31, 2012 compared to 2011 as an increase in the DD&A expense rate was partially offset by a decreased expense from lower production volumes in 2012. The DD&A expense rate per Mcfe increased to $2.96 for the 2012annual period compared to $2.38 during the same period in 2011 due to the effect of the netdownward revision in this Partnership’s proved developed producing reserves as of December 31, 2012.

Impairment of Natural Gas and Crude Oil Properties

This Partnership assesses its proved natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. This Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to 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 natural gas and crude oil properties.

If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. This Partnership's estimated production used in the impairment testing is provided by the annual reserve report. Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. There were no impairment charges for this partnership in 2012 or 2011.

Discontinued Operations

In February 2011, this Partnership sold 100% of its North Dakota assets. Proceeds from the sale were $5.7 million, resulting in a gain of $3.3 million. This Partnership had $0.2 million in revenues and $0.1 million in income from the North Dakota assets during the year ended December 31, 2011. See Note 10, Divestiture and Discontinued Operations, to this Partnership's financial statements included elsewhere in this report for additional information regarding the divestiture of this Partnership's North Dakota assets.

Financial Condition, Liquidity and Capital Resources

This Partnership's primary sources of cash for both the 2012 and 2011annual periods were from funds from operating activities, which include the sale of natural gas, NGLs and crude oil production, and the net realized gains from this Partnership's derivative positions. In addition, during the year ended December 31,2011, this Partnership also received $5.7 million in proceeds from the divestiture of this Partnership's North Dakota assets. These sources of cash were 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, $1,648,000 was paid to the Managing General Partner to cover the cost of initiating both recompletions and refracturing of certain Partnership's wells and for major repair projects. For additional information, see Results of Operations−Recent Developments−Additional Development Plan.

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Fluctuations in this Partnership's operating cash flows are substantially driven by changes in commodity prices, sales volumes, which can be impacted by high line pressures, and realized gains and losses from commodity contracts. Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through the use of derivatives. Therefore, the primary source of cash flows from operations becomes the net activity between natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. This Partnership does not engage in speculative positions, nor does this Partnership hold derivative instruments for 100% of this Partnership's expected future production from producing wells, and therefore may still experience significant fluctuations in cash flows from operations. As of December 31, 2012, this Partnership had natural gas derivative positions in place covering all of its expected natural gas production for the year ending December 31, 2013 at an average price of $5.24 per Mcf. This Partnership has no NGLs or crude oil derivatives. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on this Partnership's revenues.

This Partnership's future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity derivatives. Natural gas, NGLs and crude oil production from 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 natural gas, NGLs and crude oil 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 2013 and beyond, and may substantially reduce or restrict this Partnership's ability to participate in the additional development activities which are more fully described in Recent Developments−Additional Development Plan above.

Although the 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, 2012, this Partnership had a working capital surplus of $2.5 million, compared to a working capital surplus of $3.9 million at December 31, 2011. The decrease of $1.4 million was primarily due to the following changes:

• cash and cash equivalents decreased by $1.7 million between December 31, 2012 and December 31, 2011;

• realized and unrealized derivative gains receivable decreased by $0.2 million between December 31, 2012 and December 31, 2011; and

• amounts due to Managing General Partner-other, net, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, decreased by $0.5 million between December 31, 2012 and December 31, 2011.

Funding for the Additional Development Plan and major repair projects of $1,720,000 was provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners. Funds of $1,648,000 were utilized for payment of development activities and major repair projects during 2012. Due to the decision to suspend Additional Development Plan activities until pipeline capacity improves, unused funds of $72,000 were proportionately distributed during the fourth quarter of 2012. If the Additional Development Plan recommences future working capital balances are expected to similarly 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 cash flows from operating activities are primarily impacted by commodity prices, production volumes, realized gains and losses from 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.

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Net cash flows from operating activities were $3 million for the year ended December 31, 2012 compared to $4.4 million in 2011. The decrease of $1.4 million in cash from operating activities was due primarily to the following:

• a decrease in natural gas, NGLs and crude oil sales receipts of $3.2 million;

• an increase in commodity price risk management realized gain receipts of $1.4 million; and

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

Investing Activities

From time to time, this Partnership invests in equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. This Partnership also invests in equipment and services to complete refracturing or recompletion opportunities pursuant to the Additional Development Plan. These amounts totaled $1.3 million and $0.1 million for the years ended December 31, 2012 and 2011, respectively. Substantially all of the 2012 investment is attributable to activities pursuant to the Additional Development Plan.

In February 2011, the Managing General Partner executed a purchase and sale agreement for this Partnership's North Dakota assets and subsequently closed with the same unrelated third-party. Proceeds from the sale were $5.7 million.

Financing Activities

This Partnership initiated monthly cash distributions to investors in May 2007 and has distributed $82.8 million through December 31, 2012. 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.

Distributions
Year ended December 31,	Managing General Partner		Investor Partners		Total
2012	$	1,249,429	$	2,127,404	$	3,376,833
2011	3,186,969		5,426,460		8,613,429

The decrease in distributions for the year ended December 31, 2012 as compared to 2011 is primarily due to this Partnership's distribution of approximately $4.7 million of the proceeds from the sale of the North Dakota assets to the Investor Partners and Managing General Partner in the second quarter of 2011 and by a decrease in cash flows from operating activities during 2012, partially offset by higher withholdings in 2011 pursuant to the Additional Development Plan. For additional information, see Recent Developments − Additional Development Plan above.

Off-Balance Sheet Arrangements

As of December 31, 2012, 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.

Critical Accounting Policies

The Managing General Partner has identified the following policies as critical to business operations and the understanding of the results of the operations of this Partnership. The following is not a comprehensive list of all of this Partnership's accounting

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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 any available alternative 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.

Natural Gas and Crude Oil Properties

This Partnership accounts for its natural gas and crude oil properties under the successful efforts method of accounting, whereby costs of proved developed producing properties successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the units-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the units-of-production method based on estimated proved reserves.

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

Proved developed reserves are those natural gas, NGLs and crude oil quantities expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves ("PUDs") are those reserves expected to be recovered from existing wells where significant investment would be required for additional reserve development.

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

Natural Gas, NGLs and Crude Oil Sales Revenue Recognition

Natural gas, NGLs and crude oil sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. 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 natural gas, NGLs and crude oil 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.

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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 measures 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, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validates its fair value measurement through 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 uses common industry practices to develop its valuation techniques, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.

The Managing General Partner has evaluated the credit risk of the counterparties holding the derivative assets, which are primarily financial institutions who are also lenders in the Managing General Partner's revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner's evaluation, the Managing General Partner has determined that the potential impact of nonperformance of its counterparties on the fair value of this Partnership's derivative instruments was not significant.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

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, 2012, 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, 2012.

(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.

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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, 2012, based upon the criteria established in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management of the Managing General Partner concluded that this Partnership maintained effective internal control over financial reporting as of December 31, 2012.

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 quarter ended December 31, 2012, 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's fiduciary duty is to exercise its business judgment in the best interests of PDC's shareholders, and in that regard, as Managing General Partner, the best interests of this Partnership and other sponsored drilling partnerships. The Board has adopted Corporate Governance Guidelines that govern the structure and functioning of the Board and establish the Board's policies on a number of corporate governance issues.

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 2006 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 natural gas and crude oil marketing and prudent field operations cost management which support maximum cash flows; and

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

Although 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 and consultants. The Managing General Partner's principal executive officer, principal financial officer and principal accounting officer are subject to additional specific provisions under the Code of Conduct. The Managing General Partner's Code of Conduct is posted on PDC's website at www.pdce.com.

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's internet address is www.pdce.com. PDC will make available to Investor Partners audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods. PDC also filed these financial statements filed with the SEC on its website.

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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	64	President, Chief Executive Officer and Director	2009	2013
Gysle R. Shellum	61	Chief Financial Officer	—	—
R. Scott Meyers	38	Chief Accounting Officer	—	—
Barton R. Brookman, Jr.	50	Senior Vice President Exploration and Production	—	—
Daniel W. Amidon	52	Senior Vice President General Counsel and Secretary	—	—
Lance Lauck	50	Senior Vice President Corporate Development	—	—
Jeffrey C. Swoveland	57	Non-Executive Chairman and Director	1991	2014
Joseph E. Casabona	69	Director	2007	2014
Anthony J. Crisafio	60	Director	2006	2015
Larry F. Mazza	52	Director	2007	2013
David C. Parke	46	Director	2003	2014
Kimberly Luff Wakim	54	Director	2003	2015

James M. Trimblewas appointed President and Chief Executive Officer of the Company 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), a public company traded on the Australian Securities Exchange, and retired from the Board of Directors of Grand Gulf Energy, Limited in November 2011. In January 2005, Mr. Trimble founded and served until November 2010 as President and Chief Executive Officer of the U.S. subsidiary Grand Gulf Energy Company LLC, an exploration and development company focused primarily on drilling in mature basins in Texas, Louisiana and Oklahoma. From 2000 through 2004, Mr. Trimble was Chief Executive Officer of Elysium Energy and then Tex-Cal Energy LLC, both of which were privately held oil and gas companies that he 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 in 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 BBA in Accounting from the University of Texas, Arlington.

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

Barton R. Brookman, Jr. was appointed Senior Vice President Exploration and Production in March 2008. Previously, Mr. Brookman served as Vice President Exploration and Production since joining PDC in July 2005. Prior to joining PDC, Mr. Brookman worked for Patina Oil and Gas and its predecessor Snyder Oil from 1988 until 2005 in a series of operational and technical positions of increasing responsibility, ending his service as Vice President of Operations for Patina. 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 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 Lauckwas appointed Senior Vice President Corporate Development in January 2012. Previously, Mr. Lauck served as Senior Vice President Business Development since joining PDC in August 2009. Prior to joining PDC, Mr. Lauck 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 being promoted to various management-level positions in the areas of acquisitions and divestitures, corporate mergers and business development. From 1984 to 1988, Mr. Lauck worked as a production engineer for Tenneco Oil Company. Mr. Lauck graduated from the University of Missouri-Rolla with a Bachelor of Science Degree in Petroleum Engineering.

Jeffrey C. Swoveland was elected Non-Executive Chairman of the Board 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, having held those positions since 2007, 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, 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 5,200 wells, 5,000 miles of pipeline and 1,000,000 acres. As the primary direct report to the Chief Executive Officer of ECA, Mr. Casabona’s major responsibilities included strategic planning/forecasting, acquisitions, capital transactions and corporate policy, as well as executive oversight in operational and drilling activities in the continental U.S. and internationally. From 1968 until 1985, Mr. Casabona was employed at KPMG Main Hurdman, 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 of oil and gas prospects, primarily in Canada and Idaho. Mr. Casabona serves on the Audit Committee, which he Chairs.

36

Anthony J. Crisafio, a Certified Public Accountant, has served as an independent business consultant for more than fifteen years, providing financial and operational advice to businesses in a variety of industries and stages of development. He is currently serving as part-time contract Chief Financial Officer for Empire Energy USA, LLC, which operates approximately 2,500 wells primarily in New York and Kansas and is 90% owned by Empire Energy Group Limited, an energy investment company listed on the Australian Securities Exchange. He also serves as an interim Chief Financial Officer and Advisory Board member for a number of privately held companies and has been a Certified Public Accountant for more than thirty years. Mr. Crisafio served as 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.

Larry F. Mazza is Chief Executive Officer of MVB Financial Corp., the parent of multiple banks in West Virginia. He is a recognized name in West Virginia banking with more than 25 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, which is one of the fastest growing pro football websites and a 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 #1 ranked retail region West Virginia North, consisting of 33 financial centers and more than 300 employees. Mr. Mazza was employed by BB&T and its predecessors from 1986 to 2005. Previous to this, Mr. Mazza was President of Empire National Bank, having been appointed to that position at the age of 29, 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 joined KPMG, a Big Four accounting firm, as a CPA with a focus on auditing. Mr. Mazza serves on the Nominating and Governance Committee, which he Chairs, the Compensation Committee and the Special Transaction Committee.

David C. Parke has served as Managing Director in the merchant 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, the Nominating and Governance Committee and on the Special Transaction Committee.

Kimberly Luff Wakim, an attorney and 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 eighteen years. Ms. Wakim serves on the Compensation Committee, which she Chairs, the Audit Committee and the Nominating and Governance Committee.

Audit Committee

The Audit Committee is composed entirely of persons whom the Board has determined to be independent under NASDAQ Listing Rule 5605(a)(2), Section 301 of the Sarbanes-Oxley Act of 2002 and Section 10A(m)(3) of the Exchange Act. 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.

37

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 2012 or 2011 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, 2012, 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
	4,497.03
PDC Energy, Inc. (2) (3) (4) (5)	—	56.33	1.25	%	0.79	%
Investor Partners beneficially owning 5% or more, of limited partner interests	—	—	—		—

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

(2) 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 Partnership Agreement, individual investor partners may present their units to PDC for purchase subject to certain conditions; however, PDC is not obligated to purchase more than 10% of the total outstanding units during any calendar year.

(4) The Percentage of “Total Partnership Interests Beneficially Owned” by PDC with respect to its limited partnership units repurchased is determined by multiplying the percentage of limited partnership units repurchased by PDC to total limited partnership units, by the limited partners' percentage ownership in this Partnership. [(56.33 units/4,497.03 units)*63% limited partnership ownership]

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

38

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.

39

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	2012		2011
Audit Fees (1)	$	165,000	$	160,000

(1) Audit fees consist of professional service fees billed for the audit of this Partnership's annual financial statements which accompany this Partnership's 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 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.

40

PART IV

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

(b)    Exhibits index.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
3.1	Limited Partnership Agreement	10-12G/A Amend 1	000-52787	3	12/24/2007
3.2	Certificate of limited partnership which reflects the organization of this Partnership under West Virginia law	10-12G/A Amend 1	000-52787	3.1	12/24/2007
10.1	Drilling and operating agreement between this Partnership and PDC, as Managing General Partner	10-12G/A Amend 1	000-52787	10.2	12/24/2007
10.2	Form of assignment of leases to this Partnership	10-12G/A Amend 1	000-52787	10.1	12/24/2007
10.3	Audited Consolidated Financial Statements for the year ended December 31, 2012 of PDC Energy, Inc. and its subsidiaries, as Managing General Partner of this Partnership	10-K	000-07246		02/27/2013
10.4	Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and PDC Energy, Inc., dated May 18, 2009 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-Q	000-53201	10.1	05/18/2009
10.5	Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and PDC Energy, Inc., dated as of June 1, 2006 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10/A No. 3	000-53201	10.7	03/31/2009

41

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
10.6	First Amendment to the Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas and PDC Energy, Inc., dated as of June 1, 2011 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	8-K	000-07246	10.1	08/02/2011
10.7	Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and PDC Energy, Inc., dated October 28, 1999 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10/A No. 3	000-53201	10.3	03/31/2009
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

42

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
* Furnished herewith.

43

SIGNATURES

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

Rockies Region 2006 Limited Partnership

By its Managing General Partner

PDC Energy, Inc.

By: /s/ James M. Trimble

James M. Trimble

President and Chief Executive Officer

of PDC Energy, Inc.

March 27, 2013

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

Signature	Title	Date
/s/ James M. Trimble	President, Chief Executive Officer and Director	March 27, 2013
James M. Trimble	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	March 27, 2013
Gysle R. Shellum	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	March 27, 2013
R. Scott Meyers	PDC Energy, Inc. Managing General Partner of the Registrant
	(Principal accounting officer)
/s/ Jeffrey C. Swoveland	Chairman and Director	March 27, 2013
Jeffrey C. Swoveland	PDC Energy, Inc.
	Managing General Partner of the Registrant
/s/ Joseph E. Casabona	Director	March 27, 2013
Joseph E. Casabona	PDC Energy, Inc.
	Managing General Partner of the Registrant
/s/ Kimberly Luff Wakim	Director	March 27, 2013
Kimberly Luff Wakim	PDC Energy, Inc.
	Managing General Partner of the Registrant

44

Rockies Region 2006 Limited Partnership

Index to Financial Statements

Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets - December 31, 2012 and 2011	F-3
Statements of Operations - For the Years Ended December 31, 2012 and 2011	F-4
Statements of Partners' Equity - For the Years Ended December 31, 2012 and 2011	F-5
Statements of Cash Flows - For the Years Ended December 31, 2012 and 2011	F-6
Notes to Financial Statements	F-7
Supplemental Natural Gas, NGLs and Crude Oil Information - Unaudited	F-21

F-1

Report of Independent Registered Public Accounting Firm

To the Partners of the Rockies Region 2006 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 2006 Limited Partnership (the "Partnership") at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012 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

March 26, 2013

F-2

Rockies Region 2006 Limited Partnership

Balance Sheets

	December 31, 2012			December 31, 2011
Assets
Current assets:
Cash and cash equivalents	$	102,746		$	1,822,783
Accounts receivable	397,981			405,641
Crude oil inventory	54,336			38,542
Due from Managing General Partner-derivatives	2,716,225			3,070,411
Due from Managing General Partner-other, net	581,958			—
Total current assets	3,853,246			5,337,377
Natural gas and crude oil properties, successful efforts method, at cost	56,225,234			54,900,081
Less: Accumulated depreciation, depletion and amortization	(31,815,932		)	(28,690,196		)
Natural gas and crude oil properties, net	24,409,302			26,209,885
Due from Managing General Partner-derivatives	—			2,368,239
Other assets	107,060			63,014
Total Assets	$	28,369,608		$	33,978,515
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	138,008		$	67,859
Due to Managing General Partner-derivatives	1,234,943			1,345,134
Due to Managing General Partner-other, net	—			8,352
Total current liabilities	1,372,951			1,421,345
Due to Managing General Partner-derivatives	—			1,173,778
Asset retirement obligations	1,265,694			1,187,708
Total liabilities	2,638,645			3,782,831
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	4,584,442			6,236,390
Limited Partners - 4,497.03 units issued and outstanding	21,146,521			23,959,294
Total Partners' equity	25,730,963			30,195,684
Total Liabilities and Partners' Equity	$	28,369,608		$	33,978,515

See accompanying notes to financial statements.

F-3

Rockies Region 2006 Limited Partnership

Statements of Operations

	Year ended December 31,
	2012			2011
Revenues:
Natural gas, NGLs and crude oil sales	$	4,128,970		$	6,300,752
Commodity price risk management gain, net	657,892			2,466,855
Total revenues	4,786,862			8,767,607
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	2,467,239			3,080,932
Direct costs - general and administrative	203,789			219,784
Depreciation, depletion and amortization	3,125,736			2,969,780
Accretion of asset retirement obligations	77,986			54,046
Total operating costs and expenses	5,874,750			6,324,542
Income (loss) from continuing operations	(1,087,888		)	2,443,065
Interest income	—			3,352
Net income (loss) from continuing operations	(1,087,888		)	2,446,417
Income from discontinued operations	—			3,440,319
Net income (loss)	$	(1,087,888	)	$	5,886,736
Net income (loss) allocated to partners	$	(1,087,888	)	$	5,886,736
Less: Managing General Partner interest in net income (loss)	(402,519		)	2,178,093
Net income (loss) allocated to Investor Partners	$	(685,369	)	$	3,708,643
Net income (loss) per Investor Partner unit	$	(152	)	$	825
Investor Partner units outstanding	4,497.03			4,497.03

See accompanying notes to financial statements.

F-4

Rockies Region 2006 Limited Partnership

Statements of Partners' Equity

For the Years Ended December 31, 2012 and 2011

				Managing
	Investor			General
	Partners			Partner			Total
Balance, December 31, 2010	$	25,677,111		$	7,245,266		$	32,922,377
Distributions to partners	(5,426,460		)	(3,186,969		)	(8,613,429		)
Net income	3,708,643			2,178,093			5,886,736
Balance, December 31, 2011	23,959,294			6,236,390			30,195,684
Distributions to partners	(2,127,404		)	(1,249,429		)	(3,376,833		)
Net loss	(685,369		)	(402,519		)	(1,087,888		)
Balance, December 31, 2012	$	21,146,521		$	4,584,442		$	25,730,963

See accompanying notes to financial statements.

F-5

Rockies Region 2006 Limited Partnership

Statements of Cash Flows

	Year ended December 31,
	2012			2011
Cash flows from operating activities:
Net income (loss)	$	(1,087,888	)	$	5,886,736
Adjustments to net income (loss) to reconcile to net cash    from operating activities:
Depreciation, depletion and amortization	3,125,736			2,969,780
Accretion of asset retirement obligations	77,986			54,046
Unrealized (gain) loss on derivative transactions	1,438,456			(1,945,833		)
Gain on sale of natural gas and crude oil properties	—			(3,292,142		)
Changes in assets and liabilities:
Accounts receivable	7,660			352,281
Crude oil inventory	(15,794		)	15,981
Other assets	(44,046		)	(49,668		)
Accounts payable and accrued expenses	70,149			(146,139		)
Due to Managing General Partner-other, net	(8,352		)	8,352
Due from Managing General Partner-other, net	(581,958		)	557,042
Net cash from operating activities	2,981,949			4,410,436
Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	(1,325,153		)	(131,630		)
Proceeds from sale of natural gas and crude oil properties	—			5,684,623
Net cash from investing activities	(1,325,153		)	5,552,993
Cash flows from financing activities:
Distributions to Partners	(3,376,833		)	(8,613,429		)
Net cash from financing activities	(3,376,833		)	(8,613,429		)
Net change in cash and cash equivalents	(1,720,037		)	1,350,000
Cash and cash equivalents, beginning of period	1,822,783			472,783
Cash and cash equivalents, end of period	$	102,746		$	1,822,783
Supplemental disclosure of non-cash activity:
Asset retirement obligation, with corresponding change in natural gas and crude oil properties	$	—		$	35,037

See accompanying notes to financial statements.

F-6

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

NOTE 1 - GENERAL

Rockies Region 2006 Limited Partnership (“Partnership” or the “Registrant”) was organized in 2006 as a limited partnership, in accordance with the laws of the State of West Virginia, for the purpose of engaging in the exploration and development of natural gas and crude oil properties. Business operations commenced upon closing of an offering for the private placement of Partnership units. Upon funding, this Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes PDC Energy, Inc. (“PDC”) to conduct and manage this Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of this Partnership and initiates and completes substantially all Partnership transactions.

As of December 31, 2012, there were 2,007 limited partners in this Partnership (“Investor Partners”). 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, 2012, the Managing General Partner had repurchased 56.3 units of Partnership interests from the Investor Partners at an average price of $5,273 per unit. As of December 31, 2012, the Managing General Partner owned 37.80% of this Partnership.

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, natural gas liquids (“NGLs”) and crude oil sales revenue, proved reserves, future cash flows from natural gas and crude oil properties and valuation of derivative instruments.

Basis of Presentation

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of 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 natural gas, NGLs and crude oil. This Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by 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, 2012 or 2011.

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.

F-7

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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

All derivative assets and liabilities are recorded on the balance sheets at fair value. PDC, as Managing General Partner, has elected not to designate any of this Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of this Partnership's derivative instruments are recorded in this Partnership's statements of operations and this Partnership's net income is subject to greater volatility than if this Partnership's derivative instruments qualified for hedge accounting. Changes in the fair value of derivative instruments related to this Partnership's natural gas and crude oil sales and the realized gain or loss upon the settlement of these instruments are recorded in the line captioned, “Commodity price risk management gain, net.” As positions designated to this Partnership settle, the realized gains and losses are netted for distribution. Net realized gains are paid to this Partnership and net realized losses are deducted from this Partnership's cash distributions generated from production. This Partnership bears its proportionate share of counterparty risk.

The validation of the derivative instrument's fair value is performed by the Managing General Partner. While the Managing General Partner uses common industry practices to develop this Partnership's valuation techniques, changes in this Partnership's pricing methodologies or the underlying assumptions could result 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 and a summary fair value table of open positions as of December 31, 2012 and 2011.

Natural Gas and Crude Oil Properties. This Partnership accounts for its natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the units-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the units-of-production method based on estimated proved reserves. This Partnership calculates quarterly depreciation, depletion and amortization ("DD&A") expense by using as the denominator this Partnership's estimated quarter-end reserves, adjusted to add back current period production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A. See Supplemental Natural Gas, NGLs and Crude Oil 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 natural gas and crude oil wells. This Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of natural gas, NGLs and crude oil which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations. Annually, the Managing General Partner engages independent petroleum engineers to prepare a reserve and economic evaluation of 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 natural gas, NGLs and crude oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent 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. This Partnership assesses its producing natural gas and crude oil properties for possible impairment, upon a triggering event, 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 natural gas and crude

F-8

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

oil. 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 natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis 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 natural gas and crude oil properties with a corresponding reduction to natural gas and crude oil 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 natural gas, NGLs and crude oil. This Partnership's share of these taxes is expensed to the account “Natural gas, NGLs and crude oil production costs.” 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 are depleted over the useful lives of the related assets through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, revisions to estimated retirement costs and changes in the estimated timing of settling retirement obligations. See Note 6, Asset Retirement Obligations, for a reconciliation of the changes in this Partnership's asset retirement obligation activity.

Revenue Recognition. Natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. This Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of this Partnership's sales when 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, NGLs and crude oil is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well. Virtually all of the Managing General Partner's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and quality of the natural gas.

Revision of Prior Period Financial Statements

In connection with the preparation of its financial statements as of, and for the year ended, December 31, 2012, this Partnership revised its financial statements as of, and for the year ended, December 31, 2011 to correct an error that overstated the gain on sale of its North Dakota properties during the quarter ended March 31, 2011. Net cash flows were not affected by this revision. This Partnership assessed the materiality of this error on prior periods' financial statements in accordance with Accounting Standards Codification ("ASC") 250 (SEC Staff Accounting Bulletin No. 99, Materiality), and concluded that the error was not material to any prior annual or interim periods, but the adjustment necessary to correct the error would be material if the correction was recorded during the year ended December 31, 2012. Accordingly, in accordance with ASC 250 (SEC Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements), the financial statements as of, and for the year ended, December 31, 2011, which are presented herein, have been revised.

F-9

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

The following are selected line items from our financial statements illustrating the effect of the error correction:

	As					As
	Reported		Adjustment			Revised
Balance Sheet as of December 31, 2011
Assets:
Natural gas and crude oil properties, at cost	$	55,123,493	$	(223,412	)	$	54,900,081
Partners' Equity:
Managing General Partner	$	6,319,052	$	(82,662	)	$	6,236,390
Limited Partners - 4,497.03 units issued and outstanding	24,100,044		(140,750)			23,959,294
Total Partners' Equity	$	30,419,096	$	(223,412	)	$	30,195,684
Statement of Operations for the year ended December 31, 2011
Income from discontinued operations	$	3,663,731	$	(223,412	)	$	3,440,319
Net income	6,110,148		(223,412		)	5,886,736
Net income allocated to partners	$	6,110,148	$	(223,412	)	$	5,886,736
Less: Managing General Partner interest in net income	2,260,755		(82,662		)	2,178,093
Net income allocated to Investor Partners	$	3,849,393	$	(140,750	)	$	3,708,643

Recent Accounting Standards

Fair Value Measurement

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

F-10

ROCKIES REGION 2006 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. 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.

The Managing General Partner measures 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, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validates its fair value measurement through 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 uses common industry practices to develop its valuation techniques, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.

The Managing General Partner has evaluated the credit risk of the counterparties holding the derivative assets, which are primarily financial institutions who are also lenders in the Managing General Partner's corporate credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner's evaluation, the Managing General Partner has determined that the potential impact of nonperformance of its counterparties on the fair value of this Partnership's derivative instruments was not significant.

F-11

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

This Partnership's fixed-price swaps and basis swaps are included in Level 2 and its natural gas collars are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, this Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:

	Balance Sheet	December 31, 2012						December 31, 2011
	Line Item	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	2,716,225	$	—	$	2,716,225	$	2,918,416	151,995		$	3,070,411
Non-Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	—		—		—		2,368,239		—		2,368,239
Total assets		2,716,225		—		2,716,225		5,286,655		151,995		5,438,650
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	1,234,943		—		1,234,943		1,345,134		—		1,345,134
Non-Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	—		—		—		1,173,778		—		1,173,778
Total liabilities		1,234,943		—		1,234,943		2,518,912		—		2,518,912
Net asset		$	1,481,282	$	—	$	1,481,282	$	2,767,743	$	151,995	$	2,919,738

The following table presents a reconciliation of this Partnership's Level 3 measured at fair value:

	Year ended
	December 31, 2012			December 31, 2011
Fair value, net asset, beginning of period	$	151,995		$	213,723
Changes in fair value included in statement of operations line item:
Commodity price risk management gain, net	22,274			112,472
Settlements	(174,269		)	(174,200		)
Fair value, net asset, end of period	$	—		$	151,995
Change in unrealized gain (loss) relating to assets (liabilities) still held as of
December 31, 2012 and 2011, respectively, included in statement of operations line item:
Commodity price risk management gain, net	$	—		$	87,671

The significant unobservable input used in the fair value measurement of this Partnership's derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of this Partnership's Level 3 derivative contracts.

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

F-12

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

Non-Derivative Financial Assets and Liabilities

The carrying values 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, Natural Gas and Crude Oil 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 natural gas, NGLs and crude oil. To manage a portion of this Partnership's exposure to price volatility from producing natural gas and crude oil, the Managing General Partner utilizes an economic hedging strategy for this Partnership's natural gas and crude oil sales in which PDC, as Managing General Partner, enters into derivative contracts on behalf of this Partnership to protect against price declines in future periods. While the Managing General Partner structures these derivatives to reduce this Partnership's exposure to changes in price associated with the derivative commodities, they also limit the benefit this Partnership might otherwise have received from price increases in the physical market. The Managing General Partner believes this Partnership's derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2012, this Partnership had derivative instruments in place for all of its anticipated natural gas production through 2013 totaling 763,069 MMBtu. Partnership policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

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

As of December 31, 2012, this Partnership's derivative instruments were comprised of commodity fixed-price swaps and basis protection swaps.

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

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

F-13

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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

	Year ended December 31,
	2012								2011
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total			Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains	$	1,725,276		$	371,072	$	2,096,348		$	284,236		$	236,786	$	521,022
Unrealized gains (losses)	(1,725,276		)	286,820		(1,438,456		)	(284,236		)	2,230,069		1,945,833
Total	$	—		$	657,892	$	657,892		$	—		$	2,466,855	$	2,466,855

NOTE 5 - CONCENTRATION OF RISK

Accounts Receivable. This Partnership's accounts receivable are from purchasers of natural gas, NGLs and crude oil production. This Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by this Partnership's Managing General Partner. Inherent to this Partnership's industry is the concentration of natural gas, NGLs and crude oil 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, 2012 and 2011, 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, 2012 and 2011.

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

	Year ended December 31,
Major Customer	2012	2011
Suncor Energy Marketing, Inc.	54%	46%
WPX Energy Rocky Mountain, LLC	32%	40%
DCP Midstream, LP	11%	13%

Derivative Counterparties. The Managing General Partner's derivative arrangements expose this Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions who are also lenders under the Managing General Partner's revolving credit facility as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of this Partnership's derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on this evaluation, the Managing General Partner has determined that the potential impact of nonperformance of the Managing General Partner's counterparties on the fair value of this Partnership's derivative instruments was not significant.

F-14

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 6 - ASSET RETIREMENT OBLIGATIONS

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

	Year ended December 31,
	2012		2011
Balance at beginning of year	$	1,187,708	$	1,098,625
Obligations discharged with disposal of properties and asset retirements	—		(194,135		)
Revisions in estimated cash flows	—		229,172
Accretion expense	77,986		54,046
Balance at end of year	$	1,265,694	$	1,187,708

The revisions in estimated cash flows during 2011 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of wells in the Wattenberg Field. These cost increases related mostly to the costs of cement and construction materials and third-party and internal support services on a per well basis. The revision in the asset retirement obligation did not have an immediate effect in the 2011 statement of operations as the increase in the revised obligation will be accreted and the offsetting capitalized amount will be depreciated over the useful lives of respective wells.

NOTE 7 - COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Neither 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 sheet.

During the year ended December 31, 2012, as a result of the Managing General Partner's periodic review, new environmental remediation efforts liabilities were identified and this Partnership's expense for environmental remediation efforts was increased by approximately $114,000. This Partnership had recorded environmental remediation liabilities of approximately $97,000 and $23,000 as of December 31, 2012 and December 31, 2011, respectively.

The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2012 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 will not be discovered on this Partnership's properties.

F-15

ROCKIES REGION 2006 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 public market 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.

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:
Natural gas, NGLs and crude oil sales	63	%	37	%
Commodity price risk management gain (loss)	63	%	37	%
Sale of productive properties	63	%	37	%
Sale of equipment	63	%	37	%
Interest income	63	%	37	%
Partnership Operating Costs and Expenses:
Natural gas, NGLs and crude oil production and well
operations costs (a)	63	%	37	%
Depreciation, depletion and amortization expense	63	%	37	%
Accretion of asset retirement obligations	63	%	37	%
Direct costs - general and administrative (b)	63	%	37	%

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

(b) The Managing General Partner receives monthly reimbursement from 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-serve basis.

F-16

ROCKIES REGION 2006 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 2007. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:

	Year ended December 31,
	2012		2011
Cash distributions	$	3,376,833	$	8,613,429

Cash distributions decreased in 2012 compared to 2011, primarily due to the distribution of $4.7 million of the $5.7 million collected from the sale of the North Dakota assets in 2011 and by a decrease in cash flows from operating activities during 2012. These decreases were partially offset by reduced distributions to Partners in 2011 due to the withholding of $1.6 million pursuant to the Additional Development Plan.

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 is recorded on the balance sheets under the captions “Due from Managing General Partner-derivatives” in the case of net unrealized gains and “Due to Managing General Partner-derivatives” in the case of net unrealized losses.

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

	December 31, 2012			December 31, 2011
Natural gas, NGLs and crude oil sales revenues collected from this Partnership's third-party customers	$	415,189		$	415,359
Commodity price risk management, realized gain	216,630			150,668
Other (1)	(49,861		)	(574,379		)
Total Due from (to) Managing General Partner-other, net	$	581,958		$	(8,352	)

(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 the 40th month of 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 2012 and 2011 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."

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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, 2012 and 2011. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the statements of operations.    

	Year ended December 31,
	2012		2011
Well operations and maintenance (1)	$	2,182,296	$	2,486,047
Gathering, compression and processing fees (2)	206,352		234,691
Direct costs - general and administrative (3)	203,789		219,784
Refracturing and recompletion costs (4)	1,315,786		—
Cash distributions (5)	1,268,938		3,213,262

(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 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 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 natural gas, NGLs and crude oil, such as:

• well tending, routine maintenance and adjustment;

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

• preparing production related reports to 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.

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ROCKIES REGION 2006 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 expenses 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 31,2012 and 2011 include $19,509 and $26,293, 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 - DIVESTITURE AND DISCONTINUED OPERATIONS

In February 2011, the Managing General Partner executed a purchase and sale agreement and subsequently closed with an unrelated party for this Partnership's North Dakota assets. This Partnership received approximately $5.7 million for these assets resulting in a gain on sale of $3.3 million. Following the sale to the unrelated party, this Partnership does not have significant continuing involvement in the operations of, or cash flows from, these assets. Accordingly, the results of operations related to the North Dakota assets have been reported as discontinued operations in the statement of operations for the year ended December 31,2011 .

The table below presents selected operational information related to this Partnership's discontinued operations of this Partnership's North Dakota assets. While the reclassification of revenues and expenses related to discontinued operations for 2011 had no impact upon previously reported net earnings, the statement of operations data presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations. There was no activity recorded to discontinued operations for the year ended December 31, 2012.

	Year ended December 31,
Statement of Operations - Discontinued operations	2011
Revenues:
Natural gas, NGLs and crude oil sales	$	204,415
Total revenues	204,415
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	56,238
Total operating costs and expenses	56,238
Net income from discontinued operations	148,177
Gain on sale of natural gas and crude oil properties	3,292,142
Income from discontinued operations	$	3,440,319

F-19

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 11 - SUBSEQUENT EVENT

On February 4, 2013, this Partnership's Managing General Partner, PDC, entered into a Purchase and Sale Agreement (“PSA”) with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership has agreed to sell to Caerus this Partnership's Piceance Basin oil and gas properties located in Garfield County, Colorado. The aggregate cash consideration of approximately $7.8 million is subject to customary adjustments to the purchase price, including adjustments based on title and environmental due diligence to be conducted by Caerus and a 1% selling fee. The PSA does not include any of this Partnership's Wattenberg Field assets. Additionally, this Partnership has agreed to sell certain derivative instruments associated with the Piceance Basin to Caerus at fair market value. There can be no assurance that this transaction will close as planned.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Supplemental Natural Gas, NGLs and Crude Oil Information - Unaudited

Net Proved Reserves

This Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. ("Ryder Scott"), to estimate this Partnership's 2012 and 2011 natural gas, NGLs and crude oil reserves. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. 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 natural gas, NGLs and crude oil 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, 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 $1,648,000, 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 and for major repair projects 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)
2012	$	87.62	$	2.28	$	30.18
2011	88.05		3.37		41.02

(1) The prices used to estimate reserves have been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to 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.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Supplemental Natural Gas, NGLs and Crude Oil 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		Natural Gas Equivalent
	(MMcf)		(MBbl)		(MBbl)		(MMcfe)
Proved Reserves:
Proved reserves, January 1, 2011	11,651		304		1,093		20,033
Revisions of previous estimates and reclassifications	(713	)	125		(350	)	(2,063	)
Dispositions	(71	)	—		(157	)	(1,013	)
Production	(973	)	(13	)	(33	)	(1,249	)
Proved reserves, December 31, 2011	9,894		416		553		15,708
Revisions of previous estimates and reclassifications	(2,498	)	(60	)	(35	)	(3,068	)
Production	(836	)	(10	)	(27	)	(1,058	)
Proved reserves, December 31, 2012 (1)	6,560		346		491		11,582
Proved Developed Reserves, as of:
December 31, 2011	9,894		416		553		15,708
December 31, 2012	6,560		346		491		11,582

(1) Includes estimated reserve data related to this Partnership's Piceance Basin assets, which are expected to be divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 11, Subsequent Event, to this Partnership's financial statements included elsewhere in this report for additional details related to the planned divestiture of this Partnership's Piceance Basin assets. As of December 31, 2012, total proved reserves related to this Partnership's Piceance Basin include 3,378 MMcf of natural gas and 4 MBbls of crude oil, for an aggregate of 3,402 MMcfe of natural gas equivalent.

2012 Activity. At December 31, 2012, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 3,068 MMcfe. The revision includes downward revisions to previous estimates of 2,498 MMcf of natural gas, 60 MBbls of NGLs and 35 MBbls of crude oil. The downward revisions were the result of lower pricing and reduced asset performance. 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.

2011 Activity. At December 31, 2011, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 2,063 MMcfe. The revision includes downward revisions to previous estimates of 713 MMcf of natural gas and 350 MBbls of crude oil, partially offset by an upward revision of 125 MBbls of NGLs. The downward revisions for natural gas and crude oil were the result of decreased asset performance. In addition, the reduction of 1,013 MMcfe resulted from the disposition of this Partnership's North Dakota assets. The upward revision for NGLs was primarily due to a higher yield resulting from improved infrastructure as new processing plants were established in the Wattenberg Field area. Proved undeveloped reserves of 7,175 MMcfe were transferred to proved developed reserves in 2011 due to the reclassification of this Partnership's estimated Wattenberg refracture reserves as a result of the Managing General Partner's determination of the cost of a refracture becoming less significant as compared to the cost of drilling a new well. There were no proved undeveloped reserves developed in 2011.

F-22

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Supplemental Natural Gas, NGLs and Crude Oil Information - Unaudited

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

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

This Partnership is engaged solely in natural gas and crude oil activities, all of which are located in the continental United States. Drilling operations began upon funding in September 2006. Supporting continuing operations, this Partnership owns an undivided working interest in 86 gross (85.2 net) productive natural gas and crude oil wells. This Partnership owns 63 wells located in the Wattenberg Field within the Denver-Julesburg (“DJ”) Basin, north and east of Denver, Colorado and 23 wells located in the Piceance Basin, situated near the western border of Colorado.

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

	As of December 31,
	2012			2011
Leasehold costs	$	452,918		$	452,264
Development costs	55,772,316			54,447,817
Natural gas and crude oil properties, successful efforts method, at cost	56,225,234			54,900,081
Less: Accumulated DD&A	(31,815,932		)	(28,690,196		)
Natural gas and crude oil properties, net	$	24,409,302		$	26,209,885

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

This Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and crude oil or environmental protection. This Partnership also invests in equipment and services to complete refracturing or recompletion opportunities pursuant to the Additional Development Plan. These amounts totaled approximately $1.3 million and $0.1 million for 2012 and 2011, respectively. Substantially all of the 2012 investment is attributable to activities pursuant to the Additional Development Plan.

F-23