RR06-2014.12.31-10K Filing



		Page
	Part I
Item 1	Business	3
Item 1A	Risk Factors	16
Item 1B	Unresolved Staff Comments	16
Item 2	Properties	16
Item 3	Legal Proceedings	16
Item 4	Mine Safety Disclosures	16

	Part II
Item 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6	Selected Financial Data	19
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	28
Item 8	Financial Statements and Supplementary Data	29
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	48
Item 9A	Controls and Procedures	48
Item 9B	Other Information	49

	Part III
Item 10	Directors, Executive Officers and Corporate Governance	50
Item 11	Executive Compensation	54
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	55
Item 13	Certain Relationships and Related Transactions and Director Independence	55
Item 14	Principal Accountant Fees and Services	56

	Part IV
Item 15	Exhibits, Financial Statement Schedules	57

Signatures		59

The Rockies Region 2006 Limited Partnership (this “Partnership” or “Registrant”) is subject to the reporting and information requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and is as a result obligated to file periodic reports, proxy statements and other information with the United States ("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 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.

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 regarding this Partnership's business, financial condition and results of operations. PDC Energy, Inc. (“PDC”) is the Managing General Partner of this Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements may relate to, among other things: future production (including the components of such production), sales, expenses, cash flows and liquidity; estimated crude oil, natural gas and natural gas liquids ("NGLs") reserves; additional development plans; anticipated capital expenditures and projects; availability of additional midstream facilities and services, timing of that availability and related benefits to this Partnership; the impact of high line pressures; and the Managing General Partner's future strategies, plans and objectives.

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

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.

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

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

Subject to acquisition of limited partnership units under the Acquisition Plan discussed below or sale of this Partnership or its assets, the Managing General Partner expects this Partnership to continue to operate its crude oil and natural gas properties until such time this Partnership's wells are depleted or become uneconomical to produce, at which time that wells 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, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

As managing general partner of various limited partnerships, PDC has disclosed its intention to pursue, beginning in the fall of 2010, the acquisition of the limited partnership units held by limited partners other than by PDC or its affiliates (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership (the “Acquisition Plan”). Under the Acquisition Plan, any 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. PDC's Board of Directors (the "Board") has created a Special Transaction Committee composed of certain independent directors that has considered, upon Board request, the potential repurchase of certain of the sponsored drilling partnerships for which PDC serves as Managing General Partner. The Special Transaction Committee has not been asked to consider a repurchase of Rockies Region 2006 Limited Partnership at this time. There is no assurance that any potential proposed repurchase offer to any other of PDC's various limited partnerships, including this Partnership, will occur and no such repurchases are currently planned for 2015.

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.

In December 2011, PDC and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders related to the partnership repurchases completed by mergers in 2010 and 2011. The action was filed in United States District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp. The complaint primarily alleges that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In January 2014, the plaintiffs were certified as a class by the court.

In October 2014, PDC and plaintiffs’ counsel reached a settlement agreement. That agreement was signed in December 2014 and was given final court approval in March 2015. Under this settlement agreement the plaintiffs will receive a cash payment of $37.5 million, of which PDC will pay $31.5 million and insurers will pay $6 million, the class action will be dismissed with prejudice and all claims will be released.

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

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

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

Wattenberg Field, Denver-Julesburg Basin, Colorado. This Partnership operates exclusively in the Wattenberg Field, located north and east of Denver, Colorado. Its 63 wells in this field exhibit production histories typical for other vertical wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. All of this Partnership's natural gas, NGLs and/or crude oil production is located in the Wattenberg Field, making this Partnership vulnerable to risks associated with operating in a single geographical area. This Partnership’s 63 wells were all drilled in the Codell formation, with 10 also completed in the shallower Niobrara formation. This Partnership's wells in this area are generally 6,500 to 7,500 feet deep. Numerous vertical wells within the Wattenberg Field have been shut-in as a result of high line pressures, issues from hydraulic fracturing of nearby horizontal wells or well bore mechanical testing. Currently, 42 of this Partnership's wells are shut-in. These wells will remain unable to produce until the line pressures improve. With the new Lucerne II plant expected to be completed and online in mid-2015, the Managing General Partner expects line pressures to decrease and that these shut-in wells may be able to produce again.

Piceance Basin, Colorado. In June 2013, this Partnership completed the sale to Caerus Oil and Gas LLC (“Caerus”) of all of its Piceance Basin assets and certain derivatives for total consideration of approximately $7.9 million. The divestiture resulted in a decrease of crude oil and natural gas properties of $16.1 million and a decrease of accumulated depreciation, depletion and amortization of $8.2 million. The sale also resulted in a loss on divestiture of assets of approximately $76,000. In July 2013, this Partnership distributed the proceeds from the sale to the partners.

This Partnership's leases are direct interests in producing properties. This Partnership believes it holds good and defensible title to its crude oil and natural gas properties, in accordance with standards generally accepted in the industry, through the record title held in this Partnership's name, of each Partnership well's working interest. This Partnership's properties are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The Managing General Partner is not aware of any additional burdens, liens or encumbrances which are likely to materially interfere with the commercial use of its properties. Provisions of the Agreement generally relieve the Managing General Partner of liability for errors in judgment with respect to the waiver of title defects.

Crude Oil and Natural Gas Properties. This Partnership's properties consist of a working interest in the well bore in each well drilled by this Partnership. This Partnership drilled 97 wells (95.7 net) (the net number representing 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 gross (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. This Partnership's Piceance Basin and North Dakota assets were divested in June 2013 and February 2011, respectively.

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

Additional development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to 10 years after initial well drilling so that well resources are optimally utilized. This additional development would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to refracture or recomplete the individual wells and to determine the timing of any additional development activity. The timing of the refracturing or recompletion can be affected by the desire to optimize the economic return by additional development of the wells when commodity prices are at levels that are believed to provide an attractive rate of return to this Partnership. On average, past PDC refracturings or recompletions have increased production; however, not all past refracturings or recompletions have been economically successful and similar future refracturing or recompletion activities may not be economically successful. If the additional development work is performed, this Partnership will bear the direct costs of refracturing or recompletion, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of this Partnership from funds retained by the Managing General Partner from cash available for distributions. The Managing General Partner considers the cash available for distributions to be this Partnership's net cash flows from operating activities, less any net cash used in capital activities.

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

This Partnership did not conduct well refracture or recompletion projects in 2014 and 2013. Current estimated costs for well refracturings or recompletions are typically between $250,000 and $300,000 per activity. As of December 31, 2014, this Partnership has approximately 10 additional development opportunities included in the 2014 reserve report. Total withholding for these activities from this Partnership's cash available for distributions is estimated to be between $2.5 million and $3.0 million, if all of the activities are performed. The Managing General Partner will continually evaluate the timing of the additional development activities based on engineering data and a favorable commodity price environment in order to maximize the expected financial benefit of the additional well development.

During the fourth quarter of 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing or recompletion costs. However, due to the limitations in the take away capacity, and the extended timeline anticipated for the curtailments and the current depressed commodity pricing environment, the projected rates of return for refracturing and recompletion activities have significantly deteriorated. Therefore, during 2012 PDC elected to temporarily suspended the Additional Development Plan and the withholding of funds designated for this development until the high line pressure situation improves and stabilizes. Unspent funds of $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. If operating conditions and commodity pricing become more favorable, the withholding may recommence in the future. Based on these expectations, this program will materially reduce, up to 100%, cash available for distributions of this Partnership for a period of time not expected to exceed five years. However, no assurance can be given when the Additional Development Plan will recommence, if at all.

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

All of this Partnership's proved reserves are located onshore in the U.S. This Partnership's proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and applicable SEC staff rules. As of December 31, 2014, all of this Partnership's proved reserves have been estimated by Ryder Scott Company, L.P. (“Ryder Scott”), the Managing General Partner's independent petroleum engineering consulting firm.

The Managing General Partner has established a comprehensive process that governs the determination and reporting of this Partnership's proved reserves. As part of the Managing General Partner's internal control process, this Partnership's reserves are reviewed annually by an internal team composed of reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data and 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 Ryder Scott.

When preparing this Partnership's reserve estimates, Ryder Scott did not independently verify the accuracy and completeness of information and data furnished by the Managing General Partner with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties and sales of production.

Ryder Scott prepared an estimate of this Partnership's reserves in conjunction with an ongoing review by the Managing General Partner's engineers. A final comparison of data was performed to ensure that the reserve estimates were complete, determined pursuant to acceptable industry methods and with a level of detail the Managing General Partner deems appropriate. The final estimated reserve report was reviewed by the Managing General Partner's engineering staff and management prior to issuance by Ryder Scott.

The professional qualifications of the Managing General Partner's internal lead engineer primarily responsible for overseeing the preparation of this Partnership's reserve estimates qualify the engineer as a Reserves Estimator, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This position is currently being held by an employee of the Managing General Partner who holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 37 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and is a registered Professional Engineer in the State of Colorado.

Proved reserves as defined in SEC Regulation S-X Section 4-10(a) refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. This Partnership's net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. All of this Partnership's proved reserves are proved developed reserves. Proved developed reserves are quantities of crude oil, natural gas and NGLs expected to be recovered through existing wells with existing equipment and operating methods.

The SEC's reserve rules allow the 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.

Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. See Item 8, Financial Statements and Supplemental Data - Net Proved Reserves, for additional information regarding this Partnership's reserves. As of December 31, 2014 and 2013, there were no proved undeveloped reserves for this Partnership.



	Year Ended December 31,
	2014		2013
Production (1)

Crude Oil (Bbl)
Wattenberg Field	14,245		18,908
Piceance Basin (2)	—		441
Total Crude Oil	14,245		19,349

Natural gas (Mcf)
Wattenberg Field	41,767		70,748
Piceance Basin (2)	—		312,561
Total Natural Gas	41,767		383,309

NGLs (Bbl)
Wattenberg Field	5,165		7,166

Crude oil equivalent (Boe)
Wattenberg Field	26,372		37,866
Piceance Basin (2)	—		52,533
Total crude oil equivalent	26,372		90,399

Crude Oil, Natural Gas and NGLs Sales

Crude oil sales
Wattenberg Field	$	1,169,116	$	1,707,998
Piceance Basin (2)	—		35,756
Total crude oil sales	1,169,116		1,743,754

Natural gas sales
Wattenberg Field	160,000		225,602
Piceance Basin (2)	—		1,013,425
Total natural gas sales	160,000		1,239,027



	Year Ended December 31,
	2014		2013
NGLs sales
Wattenberg Field	116,860		180,122

Crude oil, natural gas and NGLs sales
Wattenberg Field	1,445,976		2,113,722
Piceance Basin (2)	—		1,049,181
Total crude oil, natural gas and NGLs sales	$	1,445,976	$	3,162,903

Average Selling Price (excluding net settlements on derivatives)

Crude Oil (per Bbl)
Wattenberg Field	$	82.07	$	90.33
Piceance Basin (2)	—		81.08
Weighted-average selling price crude oil	82.07		90.12

Natural gas (per Mcf)
Wattenberg Field	$	3.83	$	3.19
Piceance Basin (2)	—		3.24
Weighted-average selling price natural gas	3.83		3.23

NGLs (per Bbl)
Wattenberg Field	$	22.63	$	25.14

Crude oil equivalent (per Boe)
Wattenberg Field	$	54.83	$	55.82
Piceance Basin (2)	—		19.97
Weighted-average selling price crude oil equivalent	54.83		34.99

Average Production (Lifting) Cost (per Boe) (3)

Wattenberg Field	$	27.70	$	19.04
Piceance Basin (2)	—		8.44
Weighted-average production cost	27.70		12.88

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

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

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

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

Prior to July 2013, the Managing General Partner, on behalf of this Partnership in accordance with the D&O Agreement, utilized commodity based derivative instruments to manage a portion of this Partnership's exposure to price volatility with regard to this Partnership's crude oil and natural gas sales. The financial instruments generally consisted of collars, swaps and basis swaps, were NYMEX-traded and CIG-based contracts and were carried on the balance sheets at fair value with changes in fair values recognized in the statement of operations. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Commodity Price Risk Management for additional information on net settlements of derivatives for the year ended December 31, 2013. In June 2013, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated or sold to Caerus. Accordingly, as of December 31, 2014 and 2013, this Partnership did not have any derivative instruments in place for its future production. 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.

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

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

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

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

The availability, terms and cost of transportation affect this Partnership's natural gas sales. Competition among suppliers has greatly increased. Furthermore, gathering is exempt from regulation under the Natural Gas Act, thus allowing gatherers to charge unregulated rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently the Managing General Partner has seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area.

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

This Partnership's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public demand for the protection of the environment has increased dramatically in recent years. The trend of more expansive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken which restrict drilling or impose environmental protection requirements resulting in increased costs, this Partnership's business and prospects may be adversely affected.

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

Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. This Partnership would apply fracturing in any additional development activities. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA") and issued draft guidance related to this asserted regulatory authority in February 2014. The guidance explains the EPA’s interpretation of the term “diesel fuel” for permitting purposes, describes existing Underground Injection Control Class II program requirements for permitting underground injection of diesel fuels in hydraulic fracturing and also provides recommendations for EPA permit writers in implementing these requirements. From time to time, Congress has considered legislation that would provide for broader federal regulation of hydraulic fracturing and disclosure of the chemicals used in the hydraulic fracturing process.

The White House Council on Environmental Quality continues to coordinate an administration-wide review of hydraulic fracturing. The EPA continues its study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report expected in 2015, and a final, peer-reviewed report expected in 2016. 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. These ongoing studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), is also conducting a rulemaking to require disclosure of chemicals used, mandate well integrity measures and impose other requirements relating to hydraulic fracturing on federal lands. A final rule is expected in 2015.

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

In addition, during 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a $10,000 maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact to public health, safety, or welfare; require the COGCC to assess a penalty for each day there is evidence of a violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting from gross negligence or knowing and willful misconduct. In December 2014, the COGCC convened a hearing to consider proposed amendments to its regulations to implement this new legislation and address certain other issues. Among other things, the proposed amendments would create a new process for calculating penalties, new standards for determining days of violation and penalty amounts, and new restrictions on the use of informal enforcement procedures and penalty reductions for voluntary disclosures. A number of state and local government agencies, oil and gas companies, and non-governmental organizations are actively participating in this rulemaking process. We cannot predict the outcome of this rulemaking process, except that any regulatory amendments must be consistent with the 2014 legislation and, according to the COGCC, will have prospective effect. Nor can we predict how such regulatory amendments would affect the penalties assessed by the COGCC in future enforcement cases involving us. Although the proposed amendments could significantly increase future penalty amounts, the COGCC staff has stated that they will seek to ensure that penalties are fair and appropriate. In addition, any penalty must be approved by COGCC order, and any penalty order will be subject to judicial review.

In Colorado, local governing bodies have begun to issue drilling moratoriums, develop jurisdictional siting, permitting and operating requirements, and conduct air quality studies to identify potential public health impacts. For instance, in 2013 the City of Fort Collins, Colorado, adopted a ban on drilling and fracturing of new wells within city limits. In the November 2013 election, voters in the cities of Boulder, Lafayette, Fort Collins, and Brighton passed hydraulic fracturing bans. This Partnership does not currently have operations in any of these areas. If new laws or regulations that significantly restrict hydraulic fracturing or well locations continue to be adopted at local levels or are adopted at the state level, such laws could make it more difficult or costly for this Partnership to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of hydrocarbons, may preclude this Partnership's ability to execute the Additional Development Plan. If hydraulic fracturing becomes more heavily regulated as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, this Partnership's fracturing activities could become subject to additional permitting requirements and permitting delays, as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that this Partnership is ultimately able to produce from its reserves. The Managing General Partner continues to be active in stakeholder and interest groups and to engage with regulatory agencies in an open, proactive dialogue regarding these matters.

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

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

This Partnership's operations are subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from this Partnership's operations. The EPA and states continue the development of regulations to implement these requirements. This Partnership will be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. Federal New Source Performance Standards regarding oil and gas operations ("NSPS OOOO") became effective in 2012, with more amendments effective in 2013 and 2014, all of which have added administrative and operational costs. In addition, EPA has announced a comprehensive strategy to further reduce methane emissions from the oil and gas sector. EPA plans a hybrid approach using both voluntary and regulatory reduction measures. A proposed rule mandating additional reduction measures is expected in 2015 with a final rule expected in 2016. Colorado adopted new regulations to meet the requirements of NSPS OOOO and promulgated significant new rules in February 2014 relating specifically to crude oil and natural gas operations that are more stringent than NSPS OOOO and directly regulate methane emissions from affected facilities.

EPA has proposed to revise and lower the existing 75 part per billion ("ppb") national ambient air quality standard ("NAAQS") for ozone under the CAA to a range within 65-70 ppb. The EPA is also taking public comment on whether the ozone NAAQS should be revised to as low as 60 ppb. A lower ozone NAAQS in a range of 60-70 ppb could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirement and increased permitting delays and costs.

The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction where construction will disturb wetlands or other waters of the U.S. The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013, which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of proposed rules providing updated standards for what will be considered jurisdictional waters of the U.S. The proposed rules have been submitted for public comment and are expected to be finalized in 2015.

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species. The U.S. Fish and Wildlife Service in May 2014 proposed a rule to alter how it identifies critical habitat for endangered and threatened species. It is unclear when this rule will be finalized.

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.

The Managing General Partner believes that this Partnership's production capabilities and the experience of PDC's management and professional staff generally enable this Partnership to compete effectively in our industry. This Partnership encounters competition from numerous other crude oil and natural gas companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing crude oil and natural gas, obtaining desirable crude oil and natural gas leases on producing properties, obtaining drilling, pumping and other services, attracting and retaining qualified employees and obtaining capital. International developments may influence other companies to increase their domestic crude oil and natural gas exploration.

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

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

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

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

PDC, in its capacity as Managing General Partner and operator, has purchased various insurance policies and lists this Partnership as a named insured on certain of those policies, including workers' compensation, operator's bodily injury liability and property damage liability insurance, employer's liability insurance, automobile public liability insurance and operator's umbrella liability insurance and intends to maintain these policies subject to PDC's analysis of their premium costs, coverage and other factors. During drilling operations, the Managing General Partner maintained public liability insurance of not less than $10 million; however, PDC may at its sole discretion increase or decrease policy limits, change types of insurance and name PDC and this Partnership, individually or together, parties to the insurance as deemed appropriate under the circumstances, which may vary materially. As operator of this Partnership's wells, PDC requires its subcontractors to carry liability insurance coverage with respect to the subcontractors' activities. PDC's management, in its capacity as Managing General Partner, believes that in accordance with customary industry practice, adequate insurance, including insurance by PDC's subcontractors, has been provided to this Partnership with coverage sufficient to protect the Investor Partners against the foreseeable risks of operation, drilling, refracturing and reworks and ongoing productions operations. However, there can be no assurance that this insurance will be adequate to cover all losses or exposure for liability and thus, the occurrence of a significant event not fully insured against could materially adversely affect Partnership operations and financial condition.

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

Customers. PDC markets the crude oil, natural gas and NGLs from this Partnership's wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of this Partnership. Currently, PDC sells its natural gas and NGLs production to DCP, which gathers and processes the gas and liquefiable hydrocarbons produced. Natural gas and NGLs produced in Colorado may be impacted by changes in market prices on a national level, as well as changes in the market for natural gas within the Rocky Mountain Region. Sales of natural gas and NGLs from this Partnership's wells to DCP are made via open-access transportation arrangements through pipelines and may be impacted by capacity interruptions on pipelines transporting natural gas out of the region.

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

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.

As of December 31, 2014, this Partnership had 1,967 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. Through December 31, 2014, the Managing General Partner has repurchased 108.5 units of Partnership interests from Investor Partners.

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

Cash Distribution Policy. The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly. Historically, the Managing General Partner has distributed cash on a monthly basis, if funds were 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 currently distributed to the Investor Partners and PDC 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 refracturings or recompletions through bank borrowing.

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

upon the level of withholding and the results of operations, it is possible that investors could have taxable income from this Partnership without any corresponding distributions in future years. Certain events, such as a liquidation or merger or other acquisition of this Partnership, would result in cessation of all future cash payments. The exchange by a non-affiliated Investor Partner of limited partnership units for cash pursuant to any merger would be a taxable transaction for U.S. federal income tax purposes. The effects of a potential acquisition may be different for each investor partner. For more information concerning this Partnership's Additional Development Plan see Item 1, Business - Operations - Drilling and Other Development Activities - Additional Development Plan.

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

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

The Agreement permits this Partnership to borrow funds on its behalf for Partnership activities, exclusive of funds for the payment of cash distributions. This Partnership may borrow needed funds from the Managing General Partner or from unaffiliated persons. On loans or advances made available to this Partnership by the Managing General Partner, the Managing General Partner may not receive interest in excess of its interest costs, nor may the Managing General Partner receive interest in excess of the amounts which would be charged this Partnership (without reference to the Managing General Partner's financial abilities or guarantees) by unrelated banks on comparable loans for the same purpose. At this time, the Managing General Partner does not anticipate electing to fund any of the Additional Development Plan activities through bank borrowings. See Item 1, Business - Business Strategy. As this Partnership may have to pay interest on borrowed funds, the amount of Partnership funds available for distribution to the partners of this Partnership may be reduced accordingly.

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 12 months of cash distributions from production. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10% of the initial subscriptions if requested by an individual investor partner, subject to PDC's financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause this Partnership to be treated as a “publicly traded partnership” or result in the termination of this Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis.

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



	Twelve months ended December 31,
	2014		2013		Change
Number of gross productive wells (end of period)	63		63		—

Production⁽¹⁾
Crude oil (Bbl)	14,245		18,908		(25	)%
Natural gas (Mcf)	41,767		70,748		(41	)%
NGLs (Bbl)	5,165		7,166		(28	)%
Crude oil equivalent (Boe)⁽²⁾	26,372		37,866		(30	)%
Average Boe per day	72		104		(30	)%

Crude oil, natural gas and NGLs sales
Crude oil	$	1,169,116	$	1,707,998	(32	)%
Natural gas	160,000		225,602		(29	)%
NGLs	116,860		180,122		(35	)%
Total crude oil, natural gas and NGLs sales	$	1,445,976	$	2,113,722	(32	)%

Net settlements on derivatives
Natural gas	$	—	$	757,620	*

Average selling price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	82.07	$	90.33	(9	)%
Natural gas (per Mcf)	3.83		3.19		20	%
NGLs (Bbl)	22.63		25.14		(10	)%
Crude oil equivalent (per Boe)	54.83		55.82		(2	)%

Average cost per Boe
Crude oil, natural gas and NGLs production cost⁽³⁾	$	30.20	$	21.65	39	%
Depreciation, depletion and amortization	16.73		41.80		(60	)%

Operating costs and expenses
Direct costs - general and administrative	$	175,675	$	224,226	(22	)%
Depreciation, depletion and amortization	441,289		1,582,786		(72	)%
Impairment of crude oil and natural gas properties	—		9,755,361		*

Cash distributions	$	746,984	$	10,234,771	*

Changes in Crude Oil, Natural Gas and NGLs Sales Volumes. For 2014 compared to 2013, crude oil, natural gas and NGLs production, on an energy equivalency-basis, decreased 30%, primarily because 16 wells were shut-in during the majority of 2014 for state regulated well bore integrity testing, which is required prior to the drilling of a horizontal well in the immediate vicinity, and high line pressure hindering production from flowing into the gathering system. The decrease in production was also due to the normal production declines for this stage in the wells’ production life cycle.

As expected, this Partnership experienced higher than normal gathering system pressures in the Wattenberg Field by our primary third-party midstream provider during 2014. The line pressures in 2014 were within the Managing General Partner's expectations and lower than they were in 2013, primarily due to the commissioning of the O’Connor gas plant in the fall of 2013, the startup of an additional compressor station in 2014 and relatively mild summer temperatures in 2014. Ongoing industry drilling activity in the area has continued to increase volumes on the gathering system and pressures remained at 2014 summer levels through the end of 2014. The Managing General Partner believes the midstream service provider will be challenged to keep pace with industry drilling activity with new midstream infrastructure at least until the new Lucerne II plant is completed in mid-2015. This project should result in a significant increase in processing capacity and the Managing General Partner anticipates that it will address the current system pressure issues. If the line pressure is reduced as anticipated, several currently shut-in wells may come on-line, resulting in improved production and more favorable economics for refracing certain wells pursuant to the Additional Development Plan. The Managing General Partner and other operators in the field are working with the midstream service provider, which continues to implement a multi-year facility expansion program that will significantly increase the long-term gathering and processing capacity of the system. Like most producers, this Partnership relies on our third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with our production growth. As a result, the timing and availability of additional facilities going forward is beyond the Managing General Partner's control.

Crude Oil, Natural Gas and NGLs Pricing. This Partnership's results of operations depend upon many factors, particularly the price of crude oil, natural gas and NGLs and the Managing General Partner's ability to market this Partnership's production effectively. Crude oil, natural gas and NGLs prices are among the most volatile of all commodity prices. During periods of depressed commodity pricing, this Partnership is subject to decreased sales revenues and cash flows, which can have a material impact on this Partnership's overall financial results and capital expenditures.

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

This Partnership currently use the "net-back" method of accounting for crude oil, natural gas and NGLs production from the Wattenberg Field as the majority of the purchasers of these commodities also provide transportation, gathering and processing services. This Partnership sells commodities at the wellhead and collects a price and recognizes revenues based on the wellhead sales price as transportation and processing 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.

This Partnership previously used various derivative instruments to manage fluctuations in natural gas prices. In June 2013, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated. Accordingly, this Partnership no longer has any derivative instruments in place for its future production. Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production.

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

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

Changes in crude oil, natural gas and NGLs production expenses. Crude oil, natural gas and NGLs production costs from continuing operations for the year ended December 31, 2014 decreased by approximately $23,000 compared to 2013. The decrease in crude oil, natural gas and NGLs production costs was due to lower operating costs, a decrease in the rental of additional compressors used to accommodate high line pressures and a decrease in production taxes consistent with sales declines from 2013. Crude oil, natural gas and NGLs production costs per Boe increased to $30.20 during 2014 from $21.65 in 2013 due to lower volumes.

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

Changes in DD&A expense. DD&A expense for continuing operations decreased approximately $1,141,000 for the year ended December 31, 2014 compared to 2013 due to lower production volumes of 30% in 2014 and a decrease in the DD&A expense rate. The DD&A expense rate per Boe decreased to $16.73 for 2014 compared to $41.80 during 2013, primarily due to the effect of the impairment recorded on proved oil and natural gas properties in December 2013, which lowered the net book value of the properties by approximately $9.8 million.

In December 2013, this Partnership recognized an impairment charge of approximately $9.8 million associated with its Wattenberg Field proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on a discounted cash flow analysis. The most significant factor leading to the charge was a significant increase to the differential to NYMEX, which would result in significantly decreased future cash flows.

In June 2013, this Partnership divested its Piceance Basin assets for total consideration of approximately $7.9 million. The sale resulted in a loss on divestiture of assets of approximately $76,000. In July 2013, this Partnership distributed the proceeds from the divestiture of $7.9 million to the partners. Following the sale, this Partnership does not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin assets. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the statement of operations for the year ended December 31, 2013. See Note 11, Divestitures and Discontinued Operations, to the accompanying financial statements included elsewhere in this report for additional information.

This Partnership's primary source of liquidity has been cash flows from operating activities. Fluctuations in this Partnership's operating cash flows are substantially driven by changes in commodity prices and sales volumes. This source of cash has been primarily used to fund this Partnership's operating costs, direct costs-general and administrative and distributions to the Investor Partners and the Managing General Partner.

expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, this Partnership anticipates a lower annual level of crude oil, natural gas and NGLs production and, therefore, 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 2015 and beyond.

Although the D&O Agreement permits this Partnership to borrow funds on its behalf for Partnership activities, the Managing General Partner does not anticipate electing to fund any portion of this Partnership's refracturing and recompletion activities, if any, 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.

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

Cash flows from investing activities primarily consist of investments in equipment and services and proceeds received from the dispositions of crude oil and natural gas properties. From time to time, this Partnership invests in equipment which supports treatment, delivery and measurement of crude oil, natural gas and NGLs or environmental protection. During the year ended December 31, 2014, investments in equipment and services were approximately $272,000. During the year ended December 31, 2013, proceeds from the disposition of crude oil and natural gas properties were approximately $7.9 million.

This Partnership initiated monthly cash distributions to investors in May 2007 and has distributed $93.8 million through December 31, 2014. 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.

The decrease in distributions for the year ended December 31, 2014 as compared to 2013 was primarily due to the July 2013 distribution of the proceeds received for the Piceance Basin asset divestiture of $7.9 million, including $2.9 million and $5.0 million to the Managing General Partner and the Investor Partners, respectively. For additional information, see Recent Developments - Additional Development Plan above.

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

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

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

This Partnership assesses its crude oil and natural gas properties for possible impairment upon a triggering event by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. Any impairment in value is charged to impairment of crude oil and natural gas properties. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to this Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and, therefore, a reduction in undiscounted future net cash flows and an impairment of this Partnership's crude oil and natural gas properties. Although this Partnership's cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.

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

Asset retirement obligations are accounted for by recording the fair value of well plugging and abandonment obligations when incurred, which is at the time the well is spud. Upon initial recognition of an asset retirement obligation, the carrying amount of the long-lived asset is increased by the same amount as the liability. Over time, the liabilities are accreted for the change in present value. The initial capitalized costs, net of salvage value, are depleted over the useful lives of the related assets through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations.





Report of Independent Registered Public Accounting Firm		30

Balance Sheets - December 31, 2014 and 2013		31

Statements of Operations - For the Years Ended December 31, 2014 and 2013		32

Statements of Partners' Equity - For the Years Ended December 31, 2014 and 2013		33

Statements of Cash Flows - For the Years Ended December 31, 2014 and 2013		34

Notes to Financial Statements		35

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited		45

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, 2014 and 2013, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of this 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.



	December 31, 2014			December 31, 2013
Assets
Current assets:
Cash and cash equivalents	$	136,226		$	352,687
Accounts receivable	59,470			161,599
Crude oil inventory	53,793			54,478
Total current assets	249,489			568,764

Crude oil and natural gas properties, successful efforts method, at cost	13,373,707			12,521,325
Less: Accumulated depreciation, depletion and amortization	(7,893,923		)	(7,452,634		)
Crude oil and natural gas properties, net	5,479,784			5,068,691
Other assets	—			135,855
Total Assets	$	5,729,273		$	5,773,310

Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	6,278		$	14,197
Due to Managing General Partner-other, net	98,886			666
Total current liabilities	105,164			14,863
Asset retirement obligations	1,673,982			1,024,462
Total liabilities	1,779,146			1,039,325

Commitments and contingent liabilities

Partners' equity:
Managing General Partner	(3,474,466		)	(3,184,439		)
Limited Partners - 4,497.03 units issued and outstanding	7,424,593			7,918,424
Total Partners' equity	3,950,127			4,733,985
Total Liabilities and Partners' Equity	$	5,729,273		$	5,773,310



	Year Ended December 31,
	2014			2013
Revenues:
Crude oil, natural gas and NGLs sales	$	1,445,976		$	2,113,722
Commodity price risk management loss, net	—			(258,199		)
Total revenues	1,445,976			1,855,523
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	796,456			819,626
Direct costs - general and administrative	175,675			224,226
Depreciation, depletion and amortization	441,289			1,582,786
Accretion of asset retirement obligations	69,430			64,710
Impairment of crude oil and natural gas properties	—			9,755,361
Total operating costs and expenses	1,482,850			12,446,709

Loss from continuing operations	(36,874		)	(10,591,186		)
Loss from discontinued operations	—			(171,021		)

Net loss	$	(36,874	)	$	(10,762,207	)

Loss from continuing operations	$	(36,874	)	$	(10,591,186	)
Less: Managing General Partner interest in net loss from continuing operations	(13,643		)	(3,918,739		)
Net loss from continuing operations allocated to Investor Partners	$	(23,231	)	$	(6,672,447	)

Loss from discontinued operations	$	—		$	(171,021	)
Less: Managing General Partner interest in net loss from discontinued operations	—			(63,278		)
Loss from discontinued operations allocated to Investor Partners	$	—		$	(107,743	)

Net loss per Investor Partner unit
Continuing operations	$	(5	)	$	(1,484	)
Discontinued operations	—			(24		)
Net loss per Investor Partner unit	$	(5	)	$	(1,508	)

Investor Partner units outstanding	4,497.03			4,497.03



				Managing
	Investor			General
	Partners			Partner			Total

Balance, December 31, 2012	$	21,146,521		$	4,584,442		$	25,730,963

Distributions to partners	(6,447,907		)	(3,786,864		)	(10,234,771		)

Net loss	(6,780,190		)	(3,982,017		)	(10,762,207		)

Balance, December 31, 2013	7,918,424			(3,184,439		)	4,733,985

Distributions to partners	(470,600		)	(276,384		)	(746,984		)

Net loss	(23,231		)	(13,643		)	(36,874		)

Balance, December 31, 2014	$	7,424,593		$	(3,474,466	)	$	3,950,127



	Year Ended December 31,
	2014			2013
Cash flows from operating activities:
Net loss	$	(36,874	)	$	(10,762,207	)
Adjustments to net loss to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	441,289			1,698,870
Accretion of asset retirement obligations	69,430			72,385
Net change in fair value of unsettled derivatives	—			1,015,819
Loss on sale of crude oil and natural gas properties	—			76,387
Impairment of crude oil and natural gas properties	—			9,755,361
Changes in assets and liabilities:
Accounts receivable	102,129			236,382
Crude oil inventory	685			(6,126		)
Other assets	135,855			(28,795		)
Accounts payable and accrued expenses	(7,919		)	(123,811		)
Due to Managing General Partner-other, net	98,220			666
Due from Managing General Partner-other, net	—			582,024
Net cash from operating activities	802,815			2,516,955
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	(272,292		)	—
Proceeds from the sale of crude oil and natural gas properties	—			7,967,757
Net cash from investing activities	(272,292		)	7,967,757
Cash flows from financing activities:
Distributions to Partners	(746,984		)	(10,234,771		)
Net cash from financing activities	(746,984		)	(10,234,771		)

Net change in cash and cash equivalents	(216,461		)	249,941
Cash and cash equivalents, beginning of period	352,687			102,746
Cash and cash equivalents, end of period	$	136,226		$	352,687

Supplemental disclosure of non-cash activity:
Change in asset retirement obligation, with corresponding change in crude oil and natural gas properties, net of disposal	$	580,090		$	(313,617	)

Rockies Region 2006 Limited Partnership 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 crude oil and natural gas properties. Business operations commenced upon closing of an offering for the private placement of Partnership units. Upon funding, this Partnership entered into a D&O Agreement with the Managing General Partner which authorizes PDC to conduct and manage this Partnership's business. In accordance with the terms of the Agreement, the Managing General Partner is authorized to manage all activities of this Partnership and initiates and completes substantially all Partnership transactions.

As of December 31, 2014, there were 1,967 Investor Partners in this Partnership. PDC is the designated Managing General Partner of this Partnership and owns a 37% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 63% to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership, and 37% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. For more information about the Managing General Partner's limited partner unit repurchase program, see Note 8, Partners' Equity and Cash Distributions. Through December 31, 2014, the Managing General Partner had repurchased 108.5 units of Partnership interests from the Investor Partners at an average price of $3,460 per unit. As of December 31, 2014, the Managing General Partner owned 38.5% of this Partnership.

The preparation of this Partnership's financial statements in accordance with U.S. GAAP requires the Managing General Partner 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 this Partnership's financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves and impairment of proved properties.

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

Accounts Receivable and Allowance for Doubtful Accounts. This Partnership's accounts receivable are from purchasers of crude oil, natural gas and NGLs. This Partnership sells substantially all of its crude oil, natural gas and NGLs to customers who purchase crude oil, natural gas and NGLs from other partnerships managed by this Partnership's Managing General Partner. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. 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.

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.

Derivative Financial Instruments. This Partnership is exposed to the effect of market fluctuations in the prices of crude oil and natural gas. The Managing General Partner previously employed established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. All derivative assets and liabilities were previously recorded on the balance sheets at fair value. PDC, as Managing General Partner, elected not to designate any of this Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of this Partnership's derivative instruments were recorded in this Partnership's statements of operations and this Partnership's net income was subject to greater volatility than it would have been if this Partnership's derivative instruments had qualified for hedge accounting. The net settlements and the net change in fair value of unsettled derivatives are recorded in the line item captioned, “Commodity price risk management loss, net.” As positions designated to this Partnership settled, positive and negative settlements were netted for distribution. Positive settlements were paid to this Partnership and negative settlements were deducted from this Partnership's cash distributions generated from production. This Partnership bore its proportionate share of counterparty risk. As of December 31, 2014 and 2013, this Partnership had no outstanding derivative instruments.

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

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

Proved Property Impairment. Upon a triggering event, this Partnership assesses its producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of crude oil and natural gas. Certain events, including but not limited to, downward revisions in estimates to this Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of this Partnership's proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairment charges are included in the statement of operations line item "Impairment of crude oil and natural gas properties", with a corresponding reduction to "Crude oil and natural gas properties" and "Accumulated depreciation, depletion and amortization" line items on the balance sheets.

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

Asset Retirement Obligations. This Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spud. Upon initial recognition of an asset retirement obligation, this Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in present value. The initial capitalized costs, net of salvage value, are depleted over the useful lives of the related assets through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 6, Asset Retirement Obligations, for a reconciliation of the changes in this Partnership's asset retirement obligation.

Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. This Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of this Partnership's sales pursuant to which the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells this Partnership's natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by this Partnership's purchasers and reflected in the wellhead price. The majority of this Partnership's natural gas and NGLs is sold by the Managing General Partner on a long-term basis, primarily over the life of the well. Virtually all of the Managing General Partner's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and the quality of the natural gas.

Recently Issued Accounting Standard. In April 2014, the Financial Accounting Standards Board issued changes related to the criteria for determining which disposals can be presented as discontinued operations and modified related disclosure requirements. Under the new pronouncement, a discontinued operation is defined as a disposal of a component of an organization that represents a strategic shift and that has a major effect on the organization's operations and financial results. These changes are to be applied prospectively for new disposals or components of this Partnership's business classified as held for sale during interim and annual periods beginning after December 15, 2014, with early adoption permitted. Adoption of this guidance is not expected to have a significant impact on this Partnership's financial statements.

In May 2014, the FASB and the International Accounting Standards Board ("IASB") issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (a) identify the contract with the customer (b) identify the separate performance obligations in the contract (c) determine the transaction price (d) allocate the transaction price to separate performance obligations and (e) recognize revenue when (or as) each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and can be adopted under the full retrospective method or simplified transition method. Early adoption is not permitted. The Managing General Partner of this Partnership is currently evaluating the impact these changes will have on this Partnership's financial statements.

In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. The Managing

In January 2015, the FASB issued new accounting guidance eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entity to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separately in the income statement, net of tax, after income from continuing operations. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on this Partnership's financial statements.

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

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

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.

The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2014 which have not been provided for or would otherwise have a material impact on this Partnership's financial statements; however, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws or other potential sources of liability will not be discovered on this Partnership's properties.

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 described below.



			Managing
	Investor		General
	Partners		Partner
Partnership Revenue:
Crude oil, natural gas and NGLs sales	63	%	37	%
Commodity price risk management gain (loss)	63	%	37	%
Sale of productive properties	63	%	37	%
Sale of equipment	63	%	37	%
Interest income	63	%	37	%

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

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 12 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

The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly. Historically, the Managing General Partner has made distributions of Partnership cash on a monthly basis, if funds have been 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:

The following table presents Partnership transactions with the Managing General Partner for the years ended December 31, 2014 and 2013. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the statements of operations for continuing operations or in Note 11, Divestiture and Discontinued Operations, for information on discontinued operations.

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

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

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.

In December 2013, this Partnership recognized an impairment charge of $9.8 million associated with its Wattenberg Field proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on a discounted cash flow analysis. The most significant factor leading to the charge was a significant increase to the differential to NYMEX, which resulted in significantly decreased future cash flows.

Piceance Basin. In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement pursuant to which this Partnership agreed to sell to an unrelated third-party all of its Piceance Basin assets and certain derivatives. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $7.9 million. The divestiture of this Partnership's Piceance Basin assets resulted in a decrease of crude oil and natural gas properties of $16.1 million and a decrease of accumulated depreciation, depletion and amortization of $8.2 million. The sale resulted in a loss on divestiture of assets of approximately $76,000, which is included in discontinued operations.



	Year Ended
Statement of Operations - Discontinued Operations	December 31, 2013

Revenues:
Crude oil, natural gas and NGLs sales	$	1,049,181

Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	503,496
Direct costs - general and administrative expense	516,560
Depreciation, depletion and amortization	116,084
Accretion of asset retirement obligations	7,675
Loss on sale of crude oil and natural gas properties	76,387
Total operating costs and expenses	1,220,202

Loss from discontinued operations	$	(171,021	)

Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. This Partnership's net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of crude oil, natural gas and NGLs expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development. As of December 31, 2014 and 2013, 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 10 years after initial well drilling. 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.



	Natural Gas		NGLs		Crude Oil and Condensate		Crude Oil Equivalent
	(MMcf)		(MBbl)		(MBbl)		(MBoe)
Proved Reserves:

Proved reserves, January 1, 2013 (1)	6,560		346		491		1,930
Revisions of previous estimates and reclassifications	(946	)	(104	)	(165	)	(426	)
Dispositions (1)	(3,065	)	—		(4	)	(515	)
Production	(384	)	(7	)	(19	)	(90	)
Proved reserves, December 31, 2013	2,165		235		303		899

Revisions of previous estimates and reclassifications	(931	)	(90	)	(131	)	(376	)
Production	(42	)	(5	)	(14	)	(26	)
Proved reserves, December 31, 2014	1,192		140		158		497


Proved Developed Reserves, as of:

December 31, 2013	2,165		235		303		899
December 31, 2014	1,192		140		158		497

2014 Activity. As of December 31, 2014, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 376 MBoe. The revision includes downward revisions to previous estimates of 931 MMcf of natural gas, 90 MBbl of NGLs and 131 MBbl of crude oil. The downward revisions were the result of reduced asset performance. There were no proved undeveloped reserves developed in 2014. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2014.

2013 Activity. As of December 31, 2013, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 426 MBoe. The revision includes downward revisions to previous estimates of 946 MMcf of natural gas, 104 MBbl of NGLs and 165 MBbl of crude oil. The downward revisions were the result of lower pricing, reduced asset performance and a reduction in proved non-producing reserves. There was a significant increase to the differential to NYMEX. A portion of non-producing reserves were reclassified from proved to probable due to not being economically producible. The outcome of these three items significantly decreased estimated reserves. The divestiture of this Partnership's Piceance Basin assets resulted in the disposition of reserves comprised of 3,065 MMcf of natural gas and 4 MBbl of crude oil. There were no proved undeveloped reserves developed in 2013. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2013.

This Partnership is engaged solely in crude oil and natural gas activities, all of which are located in the continental United States. Drilling operations began upon funding in September 2006. This Partnership currently owns an undivided working interest in 63 gross (62.9 net) productive crude oil and natural gas wells located in the Wattenberg Field within the Denver-Julesburg Basin, north and east of Denver, Colorado.

From time-to-time, this Partnership invests in additional equipment which supports treatment, delivery and measurement of crude oil and natural gas or environmental protection. This Partnership may also invest in equipment and services to complete refracturing or recompletion opportunities pursuant to the Additional Development Plan. Substantially all of the $0.3 million investment in 2014 was for equipment and services. There were no investments for this Partnership in 2013.

This Partnership recorded an impairment charge of $9,755,361 for the year ended December 31, 2013. Accordingly, this Partnership reduced crude oil and natural gas properties by $27,587,884 and related accumulated depreciation, depletion and amortization for those properties by $17,832,523 as of December 31, 2013. See Note 10, Impairment of Crude Oil and Natural Gas Properties, for additional disclosure related to this Partnership's proved property impairments.

As of December 31, 2014, 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.

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:

Management of the Managing General Partner has assessed the effectiveness of this Partnership's internal control over financial reporting as of December 31, 2014, based upon the criteria established in “Internal Control - Integrated Framework (2013)” 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, 2014.

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.

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.

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 the Board, in accordance with Nevada law and PDC's by-laws. The Board has adopted Corporate Governance Guidelines that govern the structure and functioning of the Board and establish the Board's policies on a number of corporate governance issues.

The Managing General Partner's Board seeks to understand and oversee critical business risks. Risks are considered in every business decision, not just through Board oversight of the Managing General Partner's Risk Management system. The Board realizes, however, that it is not possible to eliminate all risk, nor is it desirable, and that appropriate risk-taking is essential to achieve the Managing General Partner's objectives. The Board's risk oversight structure provides that management report on critical business risk issues to the Board. The Audit Committee also reviews many risks and related controls in areas that it considers fundamental to the integrity and reliability of PDC's financial statements, such as counterparty risks and derivative program risks. The Managing General Partner's Board has established the Audit Committee, including a subcommittee which focuses specifically on financial reporting matters of PDC's sponsored drilling partnerships, to assist the Board in monitoring not only the integrity of the Managing General Partner's financial reporting systems and internal controls, but also PDC's legal and regulatory compliance. The Board has created a Special Transaction Committee composed of certain independent directors that has considered, upon Board request, the potential repurchase of certain of the sponsored drilling partnerships for which PDC serves as Managing General Partner. The Special Transaction Committee has not been asked to consider a repurchase of Rockies Region 2006 Limited Partnership at this time.

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:

Although this Partnership has not adopted a formal Code of Ethics, the Managing General Partner has implemented a Code of Business Conduct and Ethics, as amended (“the Code of Conduct”) that applies to all directors, officers, employees, agents and representatives of the Managing General Partner. The Managing General Partner's principal executive officer, principal financial officer and principal accounting officer are subject to additional specific provisions under the Code of Conduct. The Managing General Partner's Code of Conduct is posted on PDC's website at www.pdce.com. Any required disclosure regarding amendments to or waivers of the Code of Conduct will be posted on that site.

The Corporate Governance section of the Managing General Partner's website contains additional information including written charters for each Board committee and Board corporate governance guidelines. PDC will make available to Investor Partners audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods. PDC also filed these financial statements with the SEC on its website.



Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires

Barton R. Brookman, Jr.	52	President, Chief Executive Officer and Director	2015	2018

Gysle R. Shellum	63	Chief Financial Officer	—	—

Lance Lauck	52	Executive Vice President Corporate Development and Strategy	—	—

Scott J. Reasoner	53	Senior Vice President, Operations	—	—

Daniel W. Amidon	54	Senior Vice President, General Counsel and Secretary	—	—

Jeffrey C. Swoveland	60	Non-Executive Chairman	1991	2017

Joseph E. Casabona	71	Director	2007	2017

Anthony J. Crisafio	62	Director	2006	2015

Larry F. Mazza	54	Director	2007	2016

David C. Parke	48	Director	2003	2017

James M. Trimble	66	Director	2010	2016

Kimberly Luff Wakim	57	Director	2003	2015

Barton R. Brookman, Jr., PDC's President and Chief Executive Officer (“CEO”), was appointed to the Board on January 1, 2015, simultaneous with his appointment as PDC’s CEO. Mr. Brookman originally joined PDC in July 2005 as Senior Vice President-Exploration and Production; he was appointed to the position of Executive Vice President and Chief Operating Officer in June 2013 and then served as President and Chief Operating Officer from June 2014 through December 2014. Prior to joining PDC, Mr. Brookman worked for Patina Oil and Gas and its predecessor Snyder Oil from 1988 until 2005 in a series of operational and technical positions of increasing responsibility, ending his service at Patina as Vice President of Operations. In addition to his status of CEO of PDC, the Board has concluded that Mr. Brookman is qualified to serve as a Director because, among other things, of his many years of oil and gas industry executive management experience, his active involvement in industry groups and his knowledge of current developments and best practices in the industry. 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.

Gysle R. Shellum was 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. (now EnLink Midstream LLC) in Dallas, Texas. Crosstex Energy, L.P. is a publicly traded Delaware limited partnership whose securities are listed on the NASDAQ Global Select Market and is an independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids. Mr. Shellum holds a B.B.A. in Accounting from the University of Texas, Arlington.

Lance A. Lauck was appointed Executive Vice President Corporate Development and Strategy in January 2015. Mr. Lauck has overall responsibilities for PDC's business development, strategic planning, corporate reserves and midstream & marketing. Mr. Lauck joined PDC in August 2009 as Senior Vice President Business Development with the added responsibility of leading PDC's strategic planning efforts. Previously, he served as Vice President - Acquisitions and Business Development for Quantum Resources Management LLC from 2006 to 2009. From 1988 until 2006, Mr. Lauck worked for Anadarko Petroleum Corporation, where he initially held production, reservoir and acquisition engineering positions before being promoted to various management level positions in the areas of acquisitions and business development, ending his service as General Manager, Corporate Development. From 1984 to 1988, Mr. Lauck worked as a production engineer for Tenneco Oil Company. Mr. Lauck graduated from the University of Missouri-Rolla in 1984 with a Bachelor of Science degree in Petroleum Engineering.

Scott J. Reasoner is PDC's Senior Vice President of Operations, a position to which he was appointed effective January 2015. Mr. Reasoner joined PDC in April 2008 as Vice President of Western Operations. Mr. Reasoner has over 30 years of technical and management experience in the energy industry. Before joining PDC, he served as a Business Unit Manager with Noble Energy Inc. where he was responsible for the Mid-Continent team. Prior to his work with Noble Energy, Mr. Reasoner worked for Patina Oil and Gas Company as Production Manager and later as Vice President Operations. His earlier experience includes positions with Snyder Oil Corporation and Vessel Oil and Gas Company. Mr. Reasoner is a graduate of the Colorado School of Mines with a degree in Petroleum Engineering, has earned an MBA from the University of Colorado, and is a Registered Professional Engineer.

Daniel W. Amidon, Senior Vice President, General Counsel and Secretary, was 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 thereto, 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, Pennsylvania law firm of Buchanan Ingersoll PC from 1986 through 1992. Mr. Amidon graduated from the University of Virginia, with honors, majoring in economics. He received his J.D. from the Dickinson School of Law (now Penn State Law).

Jeffrey C. Swoveland was first elected to the Board in 1991 and was elected Non-Executive Chairman of the Board in June 2011. From 2006 until January 2014, Mr. Swoveland was first Chief Operating Officer and later President and Chief Executive Officer of ReGear Life Sciences, Inc. (previously named Coventina Healthcare Enterprises), which develops and markets medical device products. From 2000 until 2007, Mr. Swoveland served as Chief Financial Officer of Body Media, Inc., a life-science company. Prior thereto, from 1994 to September 2000, 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. 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 oil and natural gas company. The Board has concluded that Mr. Swoveland is qualified to serve as a Director because, among other things, he brings to the Board extensive corporate management, accounting and finance experience, and oil and gas industry expertise. Additionally, his service as a director of another public energy company provides leadership and knowledge of best practices that benefit PDC and his guidance and understanding of management processes of larger oil and gas companies benefits PDC as it continues to grow.

Joseph E. Casabona, a Certified Public Accountant (“CPA”), was first elected to the Board in 2007. Mr. Casabona served as CEO of Paramax Resources Ltd., a junior public Canadian oil and gas company, from 2008 until the beginning of 2011. Mr. Casabona also served as Executive Vice President and as a member of the Board of Directors of Denver-based Energy Corporation of America ("ECA"), a domestic oil and gas company, from 1985 until his retirement in May 2007. Mr. Casabona's major responsibilities with ECA included strategic and executive oversight of all matters affecting ECA. From 1968 until 1985, Mr. Casabona was employed at KPMG or its predecessors, with various titles including audit partner, where he primarily served public clients in the oil and gas industry. The Board has concluded that Mr. Casabona is qualified to serve as a Director because, among other things, he is a CPA and brings to the Board extensive first-hand experience in all aspects of the oil and gas industry, including natural gas exploration, development, acquisitions, operations and strategic planning, as well as experience in PDC's primary areas of operations. Mr. Casabona holds a BSBA from the University of Pittsburgh and a Master of Science-Mineral Economics from the Colorado School of Mines.

Anthony J. Crisafio, a CPA, was first elected to the Board in 2006. Mr. Crisafio has served as an independent business consultant for more than 20 years, providing financial and operational advice to businesses in a variety of industries. He previously served as the part-time contract Chief Financial Officer, and currently serves as a member of the Board of Directors, of Empire Energy USA, LLC, a domestic oil and gas company. Mr. Crisafio also previously served as the Interim Chief Financial Officer for the MDS Associated Companies, a domestic oil and gas company, from November 2013 to August 2014. 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, last serving as a partner from 1986 to 1989. He was responsible for several Securities and Exchange Commission ("SEC") registered client engagements and gained significant experience with oil and gas industry clients and mergers and acquisitions. Mr. Crisafio also serves as an Advisory Board member for a number of privately held companies. The Board has concluded that Mr. Crisafio is qualified to serve as a Director because, among other things, he is a CPA and brings to the Board more than 30 years of financial accounting and management expertise, with demonstrated business management and accounting experience.

Larry F. Mazza, a CPA, was first elected to the Board in 2007. Mr. Mazza is President and Chief Executive Officer of MVB Financial Corp ("MVB"), a financial services company. He has more than 27 years of experience in both large banks and small community banks and is one of seven members of the West Virginia Board of Banking and Financial Institutions, which oversees the operation of financial institutions throughout West Virginia and advises the state Commissioner of Banking. Mr. Mazza is also an entrepreneur and is co-owner of nationally-recognized sports media business Football Talk, LLC, a pro football website and content provider for NBC SportsTalk. Prior to joining MVB in 2005, Mr. Mazza was Senior Vice President & Retail Banking Manager for BB&T Bank's West Virginia North region. Mr. Mazza was employed by BB&T and its predecessors from 1986 to 2005. Prior thereto, Mr. Mazza was President of Empire National Bank, and later served as Regional President of One Valley Bank. Mr. Mazza also previously worked for KPMG (or its predecessors) as a CPA with a focus on auditing. The Board has concluded that Mr. Mazza is qualified to serve as a Director because, among other things, he is a CPA, a CEO, and has extensive leadership and banking experience. Mr. Mazza also provides an important link to community and employee stakeholders, demonstrating a continuing commitment to our workforce located in Bridgeport, West Virginia. Mr. Mazza graduated from West Virginia University with a degree in Business Administration.

David C. Parke, who was first elected to the Board in 2003, has served as a Managing Director with Burrill Securities LLC, an investment banking firm, since June 2011. From 2006 until June 2011, he was Managing Director in the investment banking group of Boenning & Scattergood, Inc., a regional investment bank. Prior to joining Boenning & Scattergood, from October 2003 to November 2006, he was a Director with the investment banking firm Mufson Howe Hunter & Company LLC. 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. The Board has concluded that Mr. Parke is qualified to serve as a Director because, among other things, he has extensive investment banking experience, including experience in the oil and gas area, allowing him to contribute broad financial and investment banking expertise to the Board and to provide guidance on capital markets and acquisition matters.

James M. Trimble, a Registered Professional Engineer (“RPE”), was first elected to the Board in 2009. Mr. Trimble served as the CEO and President of PDC from June 2011 through June 2014, and continued to serve as PDC's CEO through December of 2014 until the appointment of Mr. Brookman to the position of CEO on January 1, 2015. From 2005 until November 2010, Mr. Trimble served as Managing Director of Grand Gulf Energy, Limited (ASX: GGE) ("Grand Gulf"), and as President and CEO of Grand Gulf's U.S. subsidiary, Grand Gulf Energy Company LLC, a domestic oil and gas exploration and development company. From 2000 through 2004, Mr. Trimble was CEO of Elysium Energy and then TexCal Energy LLC, both privately held oil and gas companies. Prior thereto, he was Senior Vice President of Exploration and Production for Cabot Oil and Gas (NYSE: COG). From November 2002 until May 2006, he also served as a director of Blue Dolphin Energy (NASDAQ: BDCO), an independent oil and gas company. Mr. Trimble currently serves on the Board of Directors of Callon Petroleum Company (NYSE: CPE) and as a member of the Advisory Board of Directors of High Peak Energy, a private fund focused in the oil and gas industry. Mr. Trimble was an officer of PDC in September 2013, when each of twelve partnerships for which PDC was the managing general partner filed for bankruptcy in the federal bankruptcy court, Northern District of Texas, Dallas Division. The Board has concluded that Mr. Trimble is qualified to serve as a Director because, among other things, of his intimate knowledge of PDC having served as its past President and CEO, the fact that he is an RPE who brings many years of broad oil and gas industry executive management experience to the Board, and his knowledge of current developments and best practices in the industry.

Kimberly Luff Wakim, an attorney and CPA, was first elected to the Board in 2003. Ms. Wakim is a Partner with the law firm Clark Hill, PLC (formerly Thorp, Reed & Armstrong LLP), where she is the co-chair of the Corporate Restructuring and Bankruptcy I.C. Practice group. She has practiced law with the firm 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 20 years. The Board has concluded that Ms.

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

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

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 2014 or 2013 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.

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.

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.

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

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

3.1

Limited Partnership Agreement

10-12G/A Amend 1

000-52787

12/24/2007

3.2

Certificate of limited partnership which reflects the organization of 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, 2014 of PDC Energy, Inc. and its subsidiaries, as Managing General Partner of this Partnership.

10-K

000-07246

02/19/2015

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.

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.

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

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

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.



Signature	Title	Date
/s/ Barton R. Brookman, Jr.	President, Chief Executive Officer and Director	March 30, 2015
Barton R. Brookman, Jr.	PDC Energy, Inc. Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	March 30, 2015
Gysle R. Shellum	PDC Energy, Inc. Managing General Partner of the Registrant
	(Principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	March 30, 2015
R. Scott Meyers	PDC Energy, Inc. Managing General Partner of the Registrant
	(Principal accounting officer)

/s/ Jeffrey C. Swoveland	Chairman and Director	March 30, 2015
Jeffrey C. Swoveland	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Joseph E. Casabona	Director	March 30, 2015
Joseph E. Casabona	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Anthony J. Crisafio	Director	March 30, 2015
Anthony J. Crisafio	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Larry F. Mazza	Director	March 30, 2015
Larry F. Mazza	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Kimberly Luff Wakim	Director	March 30, 2015
Kimberly Luff Wakim	PDC Energy, Inc.
	Managing General Partner of the Registrant



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



	Large accelerated filer £		Accelerated filer £
	Non-accelerated filer £		Smaller reporting company R
	(Do not check if a smaller reporting company)



	Cash
Period	Distributions

For the year ended December 31, 2014	$	746,984
For the year ended December 31, 2013	10,234,771
For the period from this Partnership's inception to December 31, 2014	93,785,099



Period	Total Number of Units Repurchased	Average Price Paid Per Unit
October 1 - 31, 2014	1.00	$	360
November 1 - 30, 2014	1.00	305
December 1 - 31, 2014	3.50	246
Total	5.50	$	277



	Year ended December 31,
Major Customer	2014	2013
Suncor Energy Marketing, Inc.	72%	81%
DCP Midstream, LP	19%	19%


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


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


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


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


•	inaccuracy of reserve estimates and expected production rates;


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


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


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


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


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


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


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


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


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


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



	Productive Natural Gas Wells
	2014		2013
Location	Gross	Net	Gross	Net

Wattenberg Field	63.0	62.9	63.0	62.9



	As of December 31,
	2014	2013
Proved Reserves
Natural Gas (MMcf)	1,192	2,165
Crude Oil and Condensate (MBbl)	158	303
NGLs (MBbl)	140	235
Total proved reserves (MBoe)	497	899


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


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


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


•	NGLs. The majority of this Partnership's NGLs are sold at the tailgate of DCP Midstream, LP ("DCP") processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed.


•	costs of providing service, including depreciation expense;


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


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


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


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


•	amounts due to Managing General Partner-other, net, increased by $98,000.


•	a decrease in crude oil, natural gas and NGLs sales of $1,717,000;


•	a decrease in commodity price risk management net settlements of $758,000; and


•	a decrease in changes in operating assets and liabilities of $331,000.