ROCKIES REGION 2007 LP - FORM 10-K

Attached files

file	filename
EX-99.1 - REPORT OF INDEPENDENT PETROLEUM CONSULTANTS - RYDER SCOTT COMPANY, L.P. - ROCKIES REGION 2007 LP	rr07-ex991_20151231.htm
EX-32.1 - 906 CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - ROCKIES REGION 2007 LP	rr07-ex321_20151231.htm
EX-31.1 - 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - ROCKIES REGION 2007 LP	rr07-ex311_20151231.htm
EX-31.2 - 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - ROCKIES REGION 2007 LP	rr07-ex312_20151231.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

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

For the fiscal year ended December 31, 2015

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

FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-53201

Rockies Region 2007 Limited Partnership

(Exact name of registrant as specified in its charter)



	West Virginia		26-0208835
	(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

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

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

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



	Title of Each Class
	Limited Partnership Interests

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

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R

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



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

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter:

There is no trading market in the Registrant's securities. Therefore, there is no aggregate market value that is determinable as of the last business day of the registrant's most recently completed second fiscal quarter.

As of March 15, 2016, this Partnership had 4,470 units of limited partnership interest and no units of additional general partnership interest outstanding.

Rockies Region 2007 Limited Partnership

2015 Annual Report on Form 10-K

Table of Contents



		Page
	Part I
Item 1	Business	3
Item 1A	Risk Factors	14
Item 1B	Unresolved Staff Comments	14
Item 2	Properties	14
Item 3	Legal Proceedings	14
Item 4	Mine Safety Disclosures	14

	Part II
Item 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	15
Item 6	Selected Financial Data	16
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	24
Item 8	Financial Statements and Supplementary Data	25
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	43
Item 9A	Controls and Procedures	43
Item 9B	Other Information	44

	Part III
Item 10	Directors, Executive Officers and Corporate Governance	45
Item 11	Executive Compensation	49
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	49
Item 13	Certain Relationships and Related Transactions and Director Independence	50
Item 14	Principal Accountant Fees and Services	51

	Part IV
Item 15	Exhibits, Financial Statement Schedules	52

Signatures		54

PART I

WHERE YOU CAN FIND ADDITIONAL INFORMATION

The Rockies Region 2007 Limited Partnership (this “Partnership” or the “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 0001407805. You can read and copy any materials this Partnership files with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 on official business days during the hours of 10 a.m. to 3 p.m. You may obtain information on the operation of the Public Reference Room by calling the SEC at (800) SEC-0330.

UNITS OF MEASUREMENT

Definitions used throughout the document:

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

Boe - One barrel of crude oil equivalent.

Btu - British thermal unit.

MBbl - One thousand barrels of crude oil or NGLs.

MBoe - One thousand barrels of crude oil equivalent.

Mcf - One thousand cubic feet of natural gas volume.

MMcf - One million cubic feet of natural gas volume.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 regarding this Partnership's business, financial condition and results of operations. PDC Energy, Inc. (“PDC”) is the Managing General Partner of this Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the 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 NGLs reserves; anticipated capital expenditures and projects; availability of additional midstream facilities and services, timing of that availability and related benefits to this Partnership; the impact of high line pressures; and the Managing General Partner's future strategies, plans and objectives.

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

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


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


•	volatility of commodity prices for crude oil, natural gas and NGLs and the risk of an extended period of depressed prices;


•	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;


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


•	changes in estimates of proved reserves;


•	inaccuracy of reserve estimates and expected production rates;


•	potential for production decline rates from this Partnership's wells being 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, and the impact of these facilities and regional capacity on the prices this Partnership receives for its production;


•	timing and receipt of necessary regulatory permits;


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


•	future cash flows, liquidity and financial condition;


•	competition within the oil and gas industry;


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


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


•	cost of pending or future litigation;


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


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


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

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

ITEM 1. BUSINESS

General Information

This Partnership is a privately subscribed West Virginia Limited Partnership which owns an undivided working interest in wells located in Colorado, from which this Partnership produces and sells crude oil, natural gas and NGLs. This Partnership was organized and began operations in 2007 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”) and the Managing General Partner. The Investor Partners own 63% of this Partnership's capital or equity interests (which are sometimes referred to as units). PDC, a Delaware 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 which 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 to the sale or liquidation 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, 2057, 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.

The address and telephone number of this Partnership's and PDC's principal executive offices are 1775 Sherman Street, Suite 3000, Denver, Colorado 80203 and (303) 860-5800, respectively.

Business Strategy

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

Operations

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

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.

Area of Operations

Wattenberg Field, Denver-Julesburg Basin, Colorado. This Partnership operates exclusively in the Wattenberg Field, located north and east of Denver, Colorado. Its 75 wells in this field exhibit production histories typical for other vertical wells located in this field with an initial high production rate and relatively rapid decline, followed by relatively lower rates of decline and production levels throughout the well's remaining life. 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 75 wells were all drilled in the Codell formation, with 67 also completed in the shallower Niobrara formation. In addition to the shallower formation well completions, this Partnership also completed wells, including one Dakota formation well and five J-Sand formation wells, that currently produce from deeper formations. This Partnership's wells in this area are generally 6,500 to 7,500 feet 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, 25 of this Partnership's wells are shut-in. The Lucerne II processing plant and additional new compressor stations on the gathering system began initial operations in June 2015, resulting in immediate reductions in line pressures. This Partnership experienced further line pressure reductions in the fourth quarter of 2015, particularly in December of 2015 when the Partnership's primary service provider, DCP Midstream LP ("DCP"), completed its Grand Parkway gas gathering project. The Managing General Partner expects sustained relief of gathering system pressure on the primary gatherer's system through 2016, depending upon the impact of reduced drilling activity in the field going forward. If there is sustained relief of the gathering system pressure as anticipated, several currently shut-in wells may come on-line, resulting in improved production. However, falling commodity prices have resulted in reduced investment in midstream facilities by some third parties, increasing the risk that sufficient midstream infrastructure may not be available in future periods for sustained relief of gathering system line pressures. This Partnership recognized an impairment charge of approximately $4.6 million and $15.8 million in 2015 and 2014, respectively, to write-down certain capitalized well costs on its proved crude oil and natural gas properties. Further deterioration of commodity prices could result in additional impairment charges to this Partnership's crude oil and natural gas properties.

Title to Properties

This Partnership owns a direct interest in its 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 this Partnership's properties. Provisions of the Agreement generally relieve the Managing General Partner of liability for errors in judgment with respect to the waiver of title defects.

Drilling and Other Development Activities

Crude Oil and Natural Gas Properties. This Partnership's current properties consist of a working interest in the well bore in each of the 75 wells owned by this Partnership. This Partnership originally drilled 100 wells (98.9 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 September 2008 when the last well was connected to sales and gathering lines. During drilling operations, one Piceance Basin well was declared to be a developmental dry hole due to down-hole mechanical failure and was subsequently plugged and abandoned. This Partnership's 24 Piceance Basin wells were divested in June 2013. The 100 wells discussed above are the only wells drilled by this Partnership since all of the funds raised in this Partnership's offering were expended.

Productive wells consist of producing wells and wells capable of producing crude oil, natural gas and NGLs in commercial quantities. The following table presents the number of this Partnership's productive wells by location as of December 31, 2015 and 2014:



	Productive Natural Gas Wells
	2015		2014
Location	Gross	Net	Gross	Net

Wattenberg Field	75.0	73.9	75.0	73.9

Proved Reserves

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

All of this Partnership's proved reserves are located onshore in the U.S. This Partnership's proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. As of December 31, 2015, all of this Partnership's proved reserves have been estimated by Ryder Scott Company, L.P. (“Ryder Scott”), this Partnership'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 39 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. The Managing General Partner used a combination of performance methods including decline curve analysis and other computational methods, offset analogies, and seismic data and interpretation to calculate this Partnership's 2015 reserve estimates.

Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. See Item 8, Financial Statements and Supplemental Data - Net Proved Reserves, for additional information regarding this Partnership's reserves. As of December 31, 2015 and 2014, there were no proved undeveloped reserves for this Partnership.

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



	As of December 31,
	2015	2014
Proved Reserves
Natural Gas (MMcf)	487	3,299
Crude Oil and Condensate (MBbl)	107	455
NGLs (MBbl)	58	382
Total proved reserves (MBoe)	246	1,387

The decrease in proved reserves as of December 31, 2015 compared to December 31, 2014, was mainly due to downward revisions as a result of the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report and the removal of vertical re-fracs and re-completions from the proved developed reserves due to the current depressed commodity price environment.

Production, Sales, Prices and Lifting Costs

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



	Year Ended December 31,
	2015		2014
Production (1)

Crude Oil (Bbl)	31,613		33,159
Natural gas (Mcf)	139,137		132,398
NGLs (Bbl)	17,063		16,767
Crude oil equivalent (Boe)	71,866		71,993

Crude Oil, Natural Gas and NGLs Sales

Crude oil	$	1,238,473	$	2,701,476
Natural gas	277,967		527,219
NGLs	156,852		315,531
Total crude oil, natural gas and NGLs sales	$	1,673,292	$	3,544,226

Average Selling Price

Crude Oil (per Bbl)	$	39.18	$	81.47
Natural gas (per Mcf)	2.00		3.98
NGLs (per Bbl)	9.19		18.82
Crude oil equivalent (per Boe)	23.28		49.23

Average Production (Lifting) Cost (per Boe) (2)	$	14.52	$	11.62


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

For more information concerning this Partnership's production volumes and costs, which include severance and ad valorem taxes as reflected in this Partnership's statements of operations, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, included elsewhere in this report.

Crude Oil, Natural Gas and NGLs Sales

In accordance with the D&O Agreement, PDC markets the crude oil, natural gas and NGLs produced from this Partnership's wells. PDC does not charge an additional fee for the marketing of the crude oil, natural gas and NGLs because these services are covered by the monthly well operating charge. This monthly charge is more fully described in Item 1, Business - Reliance on the Managing General Partner - Provisions of the D&O Agreement. This Partnership's most significant customers are currently Suncor Energy Marketing, Inc., Concord Energy, LLC and DCP. Sales to these parties represented 45%, 29% and 26%, respectively, of this Partnership's 2015 revenues.

•

Crude oil. This Partnership does not refine any of its crude oil production. Crude oil is sold under various purchase contracts with monthly and longer term pricing provisions based on NYMEX pricing, adjusted for differentials. The Managing General Partner is currently pursuing various alternatives with respect to oil transportation with a view toward improving pricing. This Partnership currently has no long-term firm transportation agreements related to its crude oil production.

•

Natural gas. This Partnership primarily sells its natural gas to midstream service providers, marketers and utilities. This Partnership’s natural gas is transported through third-party gathering systems and pipelines and this Partnership incurs gathering, processing and transportation expenses to move its natural gas from the wellhead to a purchaser-specified delivery point. The Managing General Partner generally sells the natural gas that this Partnership produces under contracts with indexed, NYMEX or CIG monthly pricing provisions, with the remaining production sold under contracts with daily pricing provisions. Virtually all of this Partnership's contracts include provisions whereby prices change with the market, with certain adjustments that may be made based on whether a well delivers to a gathering or transmission line and the quality of the natural gas. The Managing General Partner believes that the pricing provisions of this Partnership's natural gas contracts are customary in the industry.


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

Transportation and Gathering

This Partnership's natural gas is transported through 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. Falling commodity prices have resulted in reduced investment in midstream facilities by some third-parties, increasing the risk that sufficient midstream infrastructure will not be available in future periods. This Partnership's natural gas is transported under firm transportation agreements through third-party processors or marketers. However, 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 sales point in Cushing, Oklahoma. The cost of trucking or transporting the crude oil to market affects the price this Partnership ultimately receives for the crude oil.

Governmental Regulation

While the prices of crude oil and natural gas are market driven, other aspects of this Partnership's business and the industry in general are heavily regulated. The availability of a ready market for crude oil and natural gas production depends on several factors that are beyond this Partnership's control. These factors include, but are not limited to, regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of crude oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. In general, state and federal regulations are intended to protect consumers from unfair treatment and 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 of the regulation of the U.S. oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental 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:


•	bond requirements in order to drill or operate wells;


•	well locations;


•	drilling and casing methods;


•	surface use and restoration of well properties;


•	well plugging and abandoning;


•	fluid disposal; and


•	air emissions.

In addition, this Partnership's drilling activities involve hydraulic fracturing, which may be subject to additional federal and state disclosure and regulatory requirements discussed below in Environmental Matters.

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 imposes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates.

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


•	costs of providing service, including depreciation expense;


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


•	volume throughput assumptions.

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

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

Environmental Matters

This Partnership's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public demand for the protection of the environment has increased dramatically in recent years. The trend towards 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.

In April 2015, EPA published proposed pretreatment standards for the oil and gas extraction industry. The proposed regulations would address discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. Some states have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There also has been recent nationwide concern over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. It is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others.

The EPA study on hydraulic fracturing below above focused on various stages of water use in hydraulic fracturing operations. It is possible that, following the conclusion and finalization of EPA’s study, the agency will move to more strictly regulate the use of water in hydraulic fracturing operations. In addition, an inability to meet water supply needs to conduct completion operations may adversely impact this Partnership's business. These water-related concerns are heightened by the potential for flooding events in Colorado such as those that occurred in 2013.

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 and issued a draft assessment in June 2015, with a final, peer-reviewed report expected in 2016. In addition, the U.S. Department of Energy has investigated 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”), also finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures, and imposing other requirements relating to hydraulic fracturing on federal lands. The rule is currently stayed and not effective pending ongoing litigation.

EPA has begun a Toxic Substances Control Act rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. EPA has not

indicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to the rulemaking. In October 2015, EPA also granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Toxics Release Inventory (“TRI”) program under the Emergency Planning and Community Right-to-Know Act of 1986. EPA determined that natural gas processing facilities may be appropriate for addition to the scope of TRI and will conduct a rulemaking process to propose such action.

Colorado has adopted regulations regarding permitting, transparency and well construction requirements with respect to hydraulic fracturing operations and may in the future adopt additional regulations or otherwise seek to ban fracturing activities 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, a rule governing setback distances of oil and gas wells located near population centers and recently adopted new rules governing the development of large-scale facilities in urban mitigation areas and additional municipality notice requirements. 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 and subsequently adopted proposed amendments to its regulations to implement this new legislation and address certain other issues. Among other things, the amendments create a new process for calculating penalties, new standards for determining days of violation and penalty amounts, new restrictions on the use of informal enforcement procedures and penalty reductions for voluntary disclosures. Following the adoption of this new penalty scheme, Colorado operators have experienced increased penalties for violations within COGCC’s jurisdiction.

In 2015, the COGCC convened hearings on regulations for large facilities located in urban mitigation areas. These new rules, which are anticipated to be effective in March 2016, require best available technology and include required mitigations for emissions, flaring, fire, fluid leak detection, repair, reporting, automated well shut-in, storage tank pressure control and proppant dust control. During these hearings, COGCC staff reported there would also be site-specific mitigation requirements for noise, ground and surface water protection, visual impacts and remote stimulation. After debate, the rule did not include duration limits despite an opinion from the State Attorney General Office that the COGCC possessed authority to impose duration limits under current and existing statutes.

Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various options for ballot initiatives aimed at significantly limiting or preventing oil and natural gas development. Two such initiatives were scheduled for a vote in the November 2014 election. One proposed to amend the Colorado constitution to establish an “environmental bill of rights” that would have allowed local governments in Colorado the right, without limitation, to prohibit crude oil and natural gas development within their respective jurisdictions. The second proposal would have imposed a statewide mandatory minimum spacing, or setback, between oil and gas wells and occupied structures of 2,000 feet. As part of a compromise negotiated by Governor John Hickenlooper, both initiatives were withdrawn prior to the election and were not voted upon. In December 2015, interest groups filed a package of 11 potential ballot initiatives focused on restricting oil and gas development in Colorado. Among other things, these initiatives, if successful, could require mandatory setbacks, allow local control over drilling, and impose prohibitions on drilling. Additional proposals of this nature may be made in the future.

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 conduct development activity. If hydraulic fracturing becomes more heavily regulated as a result of federal or state 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. Under state law, 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, as part of its comprehensive strategy to further reduce methane emissions from the oil and gas sector, EPA proposed amendments to NSPS OOOO in 2015 that would impose additional control and other requirements to reduce such emissions. A final rule is expected in the summer of 2016. In addition, on March 10, 2016, EPA announced it will begin a formal information collection request followed by a proposed rule to regulate air emissions from existing oil and natural gas sources under section 111(d) of the CAA. Depending on the final rule, the regulation of air emissions from existing sources by EPA could impose added administrative and operational costs. 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. In October 2015, the EPA strengthened the National Ambient Air Quality Standards (“NAAQS”) for ground level ozone to 70 parts per billion (“ppb”) from 75 ppb. In addition, the EPA extended the ozone monitoring season for 32 states, including Colorado. By October 2018, states are expected to have revised state implementation plans and proposed regulations to meet the new standard. In addition, the state of Colorado’s non-attainment status was raised from “marginal” to “moderate” for the Denver Metro North Front Range Ozone 8-Hour Non-Attainment area. This increase in non-attainment status triggers significant additional obligations for the state under the CAA and will result in a state rulemaking to address the new “moderate” status. This rulemaking may result in more stringent standards or additional control requirements.

In September 2015, EPA also published a proposed rule regarding source determination and permitting requirements for the onshore oil and gas industry under the CAA. The proposed rule sought public comment on two approaches for defining the term “adjacent,” which is one of three factors used to determine whether stationary sources (including oil and gas equipment and activities) are considered part of a source that is subject to major source permitting requirements under the CAA. Depending on EPA’s final approach, the oil and gas industry and this Partnership's operations could be subject to increased permitting costs and more stringent control requirements.

In January 2016, BLM proposed rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules, which would require additional controls and impose new emissions and

other standards on certain operations on applicable leases, are expected to be finalized in 2016. In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas. The public comment period for this proposal closed January 8, 2016. In May 2015, the U.S. Department of Transportation also issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, which would include this Partnership, including sampling, testing, and certification requirements.

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 the vast majority of tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the final rule issued in June 2015 defining the scope of jurisdictional waters of the U.S. This final rule has been stayed pending the resolution of ongoing litigation.

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of this Partnership's 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.

This Partnership's costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2016 and beyond. Environmental regulations have increased this Partnership's costs and planning time, but have had no materially adverse effect on this Partnership's ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on this Partnership's business, financial condition or results of operations. See Note 6, Commitments and Contingencies, to this Partnership's financial statements included elsewhere in this report.

Regulatory focus on worker safety and health regulations involving operating hazards in oil and natural gas exploration and production activities is also increasing. One example is a recent investigation by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain fuel transfer and related tasks. Several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward. For example, in December 2015, the Department of Labor and the Department of Justice, Environment and Natural Resources Division released a Memorandum of Understanding (“MOU”), announcing an inter-agency effort to increase workplace safety crimes that occur in conjunction with environmental crimes. Consistent with this MOU, the Department of Justice will look for additional felony violations (such as false statements and willful violations of certain standards) when prosecuting safety crimes in order to heighten prospective penalties and strengthen enforcement.

In addition, in December 2015, the Managing General Partner received a Compliance Advisory pursuant to C.R.S. § 25-7-115(2) from the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division alleging that the Managing General Partner failed to design, operate, and maintain certain condensate collection, storage, processing and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. The Managing General Partner is in the process of responding to the advisory, but cannot predict the outcome of this matter at this time.

Competition and Technological Changes

The Managing General Partner believes that this Partnership's production capabilities and the experience of PDC's management and professional staff generally enable this Partnership to compete effectively in its 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. This Partnership faces intense competition in other aspects of its business, including the marketing of natural gas from other producers, marketing companies and other competitors.

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.

Reliance on Managing General Partner

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

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

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

Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting and overhead services for normal production operations and may deduct from 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. 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 production 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 the control of this Partnership. Currently, PDC sells this Partnership's 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 area of this Partnership's operations. 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.

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

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

ITEM 1A. RISK FACTORS

Not applicable.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

This Partnership is not currently subject to any material pending legal proceedings. See Note 6, Commitments and Contingencies, to the accompanying financial statements included elsewhere in this report for additional information related to litigation.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

AND ISSUER PURCHASES OF EQUITY SECURITIES

As of December 31, 2015, this Partnership had 1,765 Investor Partners holding 4,470 units and one Managing General Partner. The investments held by the Investor Partners are in the form of limited partnership interests. Investor Partners' interests are transferable; however, no assignee of units in this Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. Through December 31, 2015, the Managing General Partner has repurchased 129.1 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. Beginning in the second quarter of 2015, the frequency of cash distributions, if any, was changed to a quarterly basis. 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.

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



	Cash
Period	Distributions

For the year ended December 31, 2015	$	534,304
For the year ended December 31, 2014	2,452,257
For the period from this Partnership's inception to December 31, 2015	113,362,102

The decrease in distributions for the year ended December 31, 2015 as compared to 2014 is primarily due to a decrease in cash flows from operations during 2015 resulting from the decrease in the average sales price per Boe.

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 the operator. 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.

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. The Managing General Partner does not anticipate funding this Partnership's activities through bank borrowings.

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 table presents information about the Managing General Partner's limited partner unit repurchases during each of the three months ended December 31, 2015:



Period	Total Number of Units Repurchased	Average Price Paid Per Unit
October 1 - 31, 2015	2.00	$	453
November 1 - 30, 2015	1.50	453
December 1 - 31, 2015	—	—
Total	3.50	$	453

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

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

OF OPERATIONS

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

Partnership Operating Results Overview

Crude oil, natural gas and NGLs sales decreased 53% for the year ended December 31, 2015 compared to the year ended December 31, 2014, primarily attributable to the decrease in the average sales price per Boe of 53% year over year. The average selling price per Boe was $23.28 for the current year compared to $49.23 for 2014.

As a result of the decreased sales revenues, this Partnership experienced a significant decrease in cash flows from operations. In 2015, this Partnership had net cash from operations of $469,000, as compared to net cash from operations of $2,763,000 in 2014. Accordingly, cash distributions decreased 78% to $534,000 in 2015 compared to $2,452,000 in 2014.

This Partnership recognized an impairment charge of approximately $4.6 million and $15.8 million in 2015 and 2014, respectively, to write-down certain capitalized well costs on its proved crude oil and natural gas properties. Further deterioration of commodity prices could result in additional impairment charges to this Partnership's crude oil and natural gas properties. See Note 9, Impairment of Crude Oil and Natural Gas Properties, to this Partnership's financial statements included elsewhere in this report for additional information.

The Managing General Partner has not entered into derivative arrangements on behalf of this Partnership in the last few years and does not currently anticipate entering into additional commodity based derivative instruments on behalf of this Partnership; however, this could change in the future.

Results of Operations

Summary Operating Results

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



	Year ended December 31,
	2015		2014		Change
Number of gross productive wells (end of period)	75		75		—

Production⁽¹⁾
Crude oil (Bbl)	31,613		33,159		(5	)%
Natural gas (Mcf)	139,137		132,398		5	%
NGLs (Bbl)	17,063		16,767		2	%
Crude oil equivalent (Boe)⁽²⁾	71,866		71,993		—	%
Average Boe per day	197		197		—	%

Crude oil, natural gas and NGLs sales
Crude oil	$	1,238,473	$	2,701,476	(54	)%
Natural gas	277,967		527,219		(47	)%
NGLs	156,852		315,531		(50	)%
Total crude oil, natural gas and NGLs sales	$	1,673,292	$	3,544,226	(53	)%

Average selling price
Crude oil (per Bbl)	$	39.18	$	81.47	(52	)%
Natural gas (per Mcf)	2.00		3.98		(50	)%
NGLs (Bbl)	9.19		18.82		(51	)%
Crude oil equivalent (per Boe)	23.28		49.23		(53	)%

Average cost per Boe
Crude oil, natural gas and NGLs production cost⁽³⁾	$	15.76	$	13.51	17	%
Depreciation, depletion and amortization	12.03		31.80		(62	)%

Operating costs and expenses
Crude oil, natural gas and NGLs production cost⁽³⁾	$	1,132,429	$	972,963	16	%
Direct costs - general and administrative	163,971		171,338		(4	)%
Depreciation, depletion and amortization	864,851		2,289,410		(62	)%
Impairment of crude oil and natural gas properties	4,579,916		15,760,688		(71	)%

Cash distributions	$	534,304	$	2,452,257	(78	)%

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

Amounts may not recalculate due to rounding.

_______________


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


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


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

Crude Oil, Natural Gas and NGLs Sales

Changes in Crude Oil, Natural Gas and NGLs Sales Volumes. For 2015 compared to 2014, crude oil, natural gas and NGLs production, on an energy equivalency-basis, remained relatively consistent, as decreases in production during the first half of 2015 due to high line pressure hindering production from flowing into the gathering system was largely offset by increases in production in the second half of 2015, mainly attributable to a reduction in system line pressures, the installation of new compressor stations and resumed production from certain wells that were shut-in in prior periods for well-bore integrity testing.

This Partnership continued to experience high line pressures on the midstream system in the first half of 2015. However, the Lucerne II processing plant and additional new compressor stations on the gathering system began initial operations in June 2015, resulting in immediate reductions in line pressures. This Partnership experienced further line pressure reductions in the fourth quarter of 2015, particularly in December, when this Partnership's primary service provider, DCP, completed its Grand Parkway gas gathering project. Line pressures on the midstream system decreased from approximately 170 psi at June 30, 2015 to approximately 120 psi at December 31, 2015. As a result of the reduction in line pressures during the second half of 2015, production from this Partnership's vertical wells increased by 17% in the second half of 2015 when compared to the first half. Further, the Managing General Partner expects sustained relief of gathering system pressure on this Partnership's primary gatherer's system through 2016, depending upon the impact of reduced drilling activity in the field going forward. If there is sustained relief of the gathering system pressure as anticipated, several currently shut-in wells may come on-line, resulting in improved production. This Partnership relies on its third-party midstream service provider 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 the Managing General Partner's control. Falling commodity prices have resulted in reduced investment in midstream facilities by some third parties, increasing the risk that sufficient midstream infrastructure may not be available in future periods for sustained relief of gathering system line pressures.

Changes in Crude Oil Sales. The approximate $1,463,000, or 54%, decrease in crude oil sales for 2015 as compared to 2014 was attributable to a decrease in the average selling price of 52% per Bbl and a production volume decrease of 5%. The average selling price per Bbl was $39.18 for 2015 compared to $81.47 for 2014.

Changes in Natural Gas Sales. The approximate $249,000, or 47%, decrease in natural gas sales for 2015 as compared to 2014 was due to a decrease in the average selling price per Mcf of 50%, offset in part by a production volume increase of 5%. The average selling price per Mcf was $2.00 for 2015 compared to $3.98 for 2014.

Changes in NGLs Sales. The approximate $159,000, or 50%, decrease in NGLs sales for 2015 as compared to 2014 was mainly due to a decrease in the average selling price of 51% per Bbl. The average selling price per Bbl was $9.19 for 2015 compared to $18.82 for 2014.

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. The price of crude oil decreased during the second half of 2015 compared to the first half of 2015 amid continuing concerns regarding high U.S. inventories and slowing global demand for crude oil. Natural gas prices in 2015 were at significantly lower levels than the comparable periods of 2014. NGL prices declined significantly during 2015 and, while they have stabilized somewhat, also remain at low levels relative to those experienced in 2014. The Managing General Partner expects pricing to remain at depressed levels in 2016 and perhaps beyond. These declines in prices have had a material impact on this Partnership's 2015 financial results.

This Partnership's crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. This Partnership uses the "net-back" method of accounting for natural gas and NGLs, as well as a portion of this Partnership's crude oil production 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 uses the "gross" method of accounting for crude oil delivered through the White Cliffs pipeline as the purchasers do not provide transportation, gathering or processing services. Under this method, this Partnership recognizes revenues based on the gross selling price and recognizes transportation, gathering and processing expenses as a component of production costs.

Crude Oil, Natural Gas and NGLs Production Costs

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 for the year ended December 31, 2015 increased by approximately $159,000 compared to 2014, primarily attributable to an increase in environmental and regulatory compliance expenses, costs for additional contract labor, oil transportation cost on the White Cliffs pipeline, well service rig costs and production equipment costs. These increases were offset in part by a decrease in production taxes consistent with sales declines from 2014. Crude oil, natural gas and NGLs production costs per Boe increased to $15.76 during 2015 from $13.51 in 2014 due to higher production costs.

Direct costs - general and administrative

Direct costs - general and administrative for the year ended December 31, 2015 decreased approximately $7,000 compared to 2014, primarily attributable to lower professional fees for audit services.

Depreciation, Depletion and Amortization

DD&A expense decreased approximately $1,425,000 for the year ended December 31, 2015 compared to 2014 mainly attributable to a 62% decrease in the DD&A expense rate in 2015. The DD&A expense rate per Boe decreased to $12.03 for 2015 compared to $31.80 during 2014, primarily due to the effect of the impairments recorded on proved crude oil and natural gas properties in December 2014 and September 2015.

Impairment of Crude Oil and Natural Gas Properties

In 2015, this Partnership recognized impairment charges of approximately $4.6 million to write-down certain capitalized well costs on its proved crude oil and natural gas properties, of which $1.7 million was recorded in the fourth quarter of 2015. The impairment charge represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value of approximately $1.4 million, excluding estimated salvage value of $0.5 million, was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and future crude oil and natural gas prices which the Managing General Partner reasonably expects this Partnership's crude oil and natural gas will be sold and decreased reserve quantities. Further deterioration of commodity prices could result in additional impairment charges to this Partnership's crude oil and natural gas properties. See Note 9, Impairment of Crude Oil and Natural Gas Properties, to this Partnership's financial statements included elsewhere in this report for additional information.

In 2014, this Partnership recognized an impairment charge of approximately $15.8 million to write-down certain capitalized well costs on its proved crude oil and natural gas properties. The impairment charge represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value of approximately $5.5 million, excluding estimated salvage value of $1.3 million, was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and future crude oil and natural gas prices which the Managing General Partner reasonably expects this Partnership's crude oil and natural gas will be sold and decreased reserve quantities. See Note 9, Impairment of Crude Oil and Natural Gas Properties, to this Partnership's financial statements included elsewhere in this report for additional details of this Partnership's proved property impairment.

Asset Retirement Obligations and Accretion Expense

Of the 75 wells in this partnership, 38 wells had a decrease in production totaling approximately 13.8 MBoe, or 19%, in 2015 compared to 2014 and 34 wells had an increase in production totaling approximately 13.7 MBoe, or 19%, in 2015 compared to 2014. Three wells did not produce or produced minimal amounts of hydrocarbons in 2015 and 2014. The Managing General Partner is reviewing the Partnership's wells that have the potential to increase production during this lower line pressure environment by incurring minimal expense. The Managing General Partner expects that a portion of this Partnership's wells may be uneconomical to operate and may be plugged and abandoned. As a result, as of December 31, 2015, this Partnership has classified a portion of the asset retirement obligation as a current liability.

Changes in accretion of asset retirement obligations ("ARO") expense. ARO expense increased $55,000, or 74%, to $129,000 in 2015 compared to $74,000 in 2014, primarily attributable to an increase in asset retirement obligations recorded in December 2014 to reflect increased estimated costs for materials and services related to the plugging and abandonment of certain wells, as well as a decrease in the estimated useful life of these wells.

Financial Condition, Liquidity and Capital Resources

Historically, 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 primarily been used to fund this Partnership's operating costs, direct costs-general and administrative, capital program and distributions to the Investor Partners and the Managing General Partner.

This Partnership's future operations are expected to be conducted with available funds and revenues generated from crude oil, natural gas and NGLs production activities. However, crude oil, natural gas and NGLs production from existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, this Partnership anticipates a lower annual level of crude oil, natural gas and NGLs production and, therefore, lower revenues, unless commodity prices increase. Under these circumstances, decreased production would have a material adverse impact on this Partnership's operations and may result in the continued lack of cash distributions to the Managing General Partner and Investor Partners through 2016 and beyond.

Working Capital

At December 31, 2015, this Partnership had working capital of $182,000, compared to working capital of $637,000 at December 31, 2014. The decrease of $455,000 was primarily due to the following changes:


•	a decrease in cash and cash equivalents of $133,000;


•	a decrease in accounts receivable of $46,000;


•	an increase in current asset retirement obligations of $230,000; and


•	an increase in amounts due to Managing General Partner-other, net, of $58,000.

Offset in part by;


•	a decrease in accounts payable and accrued expenses of $8,000; and


•	an increase in crude oil inventory of $4,000.

The $133,000 decrease in cash and cash equivalents is primarily attributable to cash utilized to fund operating activities, capital expenditures and cash distributions to partners.

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 operations 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.

Cash Flows

Operating Activities

This Partnership's cash flows from operating activities in 2015 were primarily impacted by commodity prices, production volumes, operating costs and direct costs-general and administrative expenses. The key components for the changes in this Partnership's cash flows from operating activities are described in more detail in Results of Operations above.

Net cash flows from operating activities were approximately $469,000 for the year ended December 31, 2015 compared to approximately $2,763,000 in 2014. The decrease of approximately $2,294,000 in cash from operating activities was due primarily to the following:


•	a decrease in crude oil, natural gas and NGLs sales of $1,871,000;


•	a decrease in changes in operating assets and liabilities of $270,000; and


•	an increase in production costs of $159,000.

Offset in part by:


•	a decrease in direct costs-general and administrative of $7,000.

Investing Activities

Cash flows from investing activities primarily consist of investments in equipment. 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, 2015, investments in equipment were approximately $68,000 compared to $252,000 in 2014.

Financing Activities

This Partnership initiated monthly cash distributions to investors in May 2008 and has distributed $113.4 million through December 31, 2015. 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. Distributions to Investor Partners represent amounts distributed to Investor Partners for their 63% ownership share in this Partnership and include amounts distributed to the Managing General Partner for limited partnership units repurchased.



Cash Distributions

Year ended December 31,	Managing General Partner		Investor Partners		Total
2015	$	197,693	$	336,611	$	534,304
2014	907,335		1,544,922		2,452,257

Off-Balance Sheet Arrangements

As of December 31, 2015, this Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on this Partnership's financial condition, results of operations, liquidity, capital expenditures or capital resources.

Commitments and Contingencies

See Note 6, Commitments and Contingencies, to the accompanying financial statements included elsewhere in this report.

Recent Accounting Standards

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

Critical Accounting Policies

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

Crude Oil, Natural Gas and NGLs Properties

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

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

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

Crude Oil, Natural Gas and NGLs Sales Revenue Recognition

Crude oil, natural gas and NGLs sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. This Partnership records sales revenue based on an estimate of the volumes delivered at estimated prices (if known, actual volumes and prices received are utilized) as determined by the applicable sales agreement. If actual volumes and prices are not known, 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.

This Partnership’s crude oil, natural gas and NGLs sales are concentrated with a few major customers. This concentrates the significance of credit risk exposure. To date, this Partnership has had no material counterparty default losses. See Note 4, Concentration of Risk, to the financial statements included elsewhere in this report.

Asset Retirement Obligations

Asset retirement obligations are accounted for by recording the fair value of well plugging and abandonment obligations when incurred, which is at the time the well is spud. Upon initial recognition of an asset retirement obligation, 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.

Recent Accounting Standards

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Rockies Region 2007 Limited Partnership

Index to Financial Statements





Report of Independent Registered Public Accounting Firm		26

Balance Sheets - December 31, 2015 and 2014		27

Statements of Operations - For the Years Ended December 31, 2015 and 2014		28

Statements of Partners' Equity - For the Years Ended December 31, 2015 and 2014		29

Statements of Cash Flows - For the Years Ended December 31, 2015 and 2014		30

Notes to Financial Statements		31

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited		40

Report of Independent Registered Public Accounting Firm

To the Partners of the Rockies Region 2007 Limited Partnership:

In our opinion, the accompanying balance sheets and the related statements of operations, partners’ equity, and cash flows present fairly, in all material respects, the financial position of Rockies Region 2007 Limited Partnership at December 31, 2015 and December 31, 2014, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 8 to the financial statements, this Partnership has significant related party transactions with this Partnership's Managing General Partner, PDC Energy, Inc., and its subsidiaries.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 25, 2016

Rockies Region 2007 Limited Partnership

Balance Sheets



	December 31, 2015			December 31, 2014
Assets
Current assets:
Cash and cash equivalents	$	495,945		$	628,520
Accounts receivable	122,055			168,421
Crude oil inventory	41,058			37,394
Total current assets	659,058			834,335

Crude oil and natural gas properties, successful efforts method, at cost	3,819,467			15,661,273
Less: Accumulated depreciation, depletion and amortization	(1,889,887		)	(8,836,596		)
Crude oil and natural gas properties, net	1,929,580			6,824,677
Total Assets	$	2,588,638		$	7,659,012

Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	11,117		$	19,545
Due to Managing General Partner-other, net	236,289			178,150
Current portion of asset retirement obligations	230,000			—
Total current liabilities	477,406			197,695

Asset retirement obligations	2,083,683			1,702,926
Total liabilities	2,561,089			1,900,621

Commitments and contingent liabilities

Partners' equity:
Managing General Partner	(5,183,755		)	(3,063,343		)
Limited Partners - 4,470 units issued and outstanding	5,211,304			8,821,734
Total Partners' equity	27,549			5,758,391
Total Liabilities and Partners' Equity	$	2,588,638		$	7,659,012

See accompanying notes to financial statements.

Rockies Region 2007 Limited Partnership

Statements of Operations



	Year Ended December 31,
	2015			2014
Revenues:
Crude oil, natural gas and NGLs sales	$	1,673,292		$	3,544,226

Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	1,132,429			972,963
Direct costs - general and administrative	163,971			171,338
Depreciation, depletion and amortization	864,851			2,289,410
Accretion of asset retirement obligations	128,663			73,793
Impairment of crude oil and natural gas properties	4,579,916			15,760,688
Total operating costs and expenses	6,869,830			19,268,192

Net loss	$	(5,196,538	)	$	(15,723,966	)

Net loss	$	(5,196,538	)	$	(15,723,966	)
Less: Managing General Partner interest in net loss	(1,922,719		)	(5,817,867		)
Net loss allocated to Investor Partners	$	(3,273,819	)	$	(9,906,099	)

Net loss per Investor Partner unit	$	(732	)	$	(2,216	)

Investor Partner units outstanding	4,470			4,470

See accompanying notes to financial statements.

Rockies Region 2007 Limited Partnership

Statements of Partners' Equity

For the Years Ended December 31, 2015 and 2014



				Managing
	Investor			General
	Partners			Partner			Total

Balance, December 31, 2013	$	20,272,755		$	3,661,859		$	23,934,614

Distributions to partners	(1,544,922		)	(907,335		)	(2,452,257		)

Net loss	(9,906,099		)	(5,817,867		)	(15,723,966		)

Balance, December 31, 2014	8,821,734			(3,063,343		)	5,758,391

Distributions to partners	(336,611		)	(197,693		)	(534,304		)

Net loss	(3,273,819		)	(1,922,719		)	(5,196,538		)

Balance, December 31, 2015	$	5,211,304		$	(5,183,755	)	$	27,549

See accompanying notes to financial statements.

Rockies Region 2007 Limited Partnership

Statements of Cash Flows



	Year Ended December 31,
	2015			2014
Cash flows from operating activities:
Net loss	$	(5,196,538	)	$	(15,723,966	)
Adjustments to net loss to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	864,851			2,289,410
Accretion of asset retirement obligations	128,663			73,793
Impairment of crude oil and natural gas properties	4,579,916			15,760,688
Changes in assets and liabilities:
Accounts receivable	46,366			210,519
Crude oil inventory	(3,664		)	17,914
Other assets	—			89,630
Accounts payable and accrued expenses	(8,428		)	(13,496		)
Due to Managing General Partner-other, net	58,139			58,156
Net cash from operating activities	469,305			2,762,648
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	(67,576		)	(252,247		)
Net cash from investing activities	(67,576		)	(252,247		)
Cash flows from financing activities:
Distributions to Partners	(534,304		)	(2,452,257		)
Net cash from financing activities	(534,304		)	(2,452,257		)

Net change in cash and cash equivalents	(132,575		)	58,144
Cash and cash equivalents, beginning of period	628,520			570,376
Cash and cash equivalents, end of period	$	495,945		$	628,520

Supplemental disclosure of non-cash activity:
Change in asset retirement obligation, with corresponding change in crude oil and natural gas properties, net of disposal	$	482,094		$	693,320

See accompanying notes to financial statements.

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

NOTE 1 - GENERAL

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

As of December 31, 2015, there were 1,765 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 7, Partners' Equity and Cash Distributions. Through December 31, 2015, the Managing General Partner had repurchased 129.1 units of Partnership interests from the Investor Partners at an average price of $2,638 per unit. As of December 31, 2015, the Managing General Partner owned 38.8% 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, future cash flows from crude oil and natural gas properties and impairment of proved properties.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

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

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

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

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NOTES TO FINANCIAL STATEMENTS - Continued

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.

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

Asset Retirement Obligations. This Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spud. Upon initial recognition of an asset retirement obligation, this Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in present value. The initial capitalized costs, net of salvage value, are depleted over the useful lives of the related assets through charges to DD&A expense. If the fair value of the estimated asset retirement

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NOTES TO FINANCIAL STATEMENTS - Continued

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 5, 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's crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the transportation method used. This Partnership 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 collects a price 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. 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 uses the "gross" method of accounting crude oil delivered through the White Cliffs pipeline as the purchasers do not provide transportation, gathering or processing services. Under this method, this Partnership recognizes revenues based on the gross selling price.

Recent Adopted Accounting Standards

In July 2015, the Financial Accounting Standards Board ("FASB") issued an accounting update requiring all entities to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. This Partnership elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on this Partnership's financial statements.

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. This Partnership elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on this Partnership's financial statements.

Recently Issued Accounting Standard.

In May 2014, the FASB and the International Accounting Standards Board 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. In August 2015, the FASB deferred the effective date of the revenue standard to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. 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

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NOTES TO FINANCIAL STATEMENTS - Continued

General Partner of this Partnership is currently evaluating the impact these changes will have on this Partnership's financial statements.

NOTE 3 - FAIR VALUE OF MEASUREMENTS

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

The Managing General Partner utilizes fair value, on a non-recurring basis, to perform impairment testing on this Partnership's crude oil and natural gas properties by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value and is measured by the amount by which the net capitalized costs exceed their fair value. See Note 9, Impairment of Crude Oil and Natural Gas Properties, for information regarding impairment charges recognized in 2015.

NOTE 4 - CONCENTRATION OF RISK

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

As of December 31, 2015 and 2014, this Partnership did not record an allowance for doubtful accounts and did not incur any losses on accounts receivable. As of December 31, 2015, this Partnership had three customers representing 10% or more of the accounts receivable balance: Suncor Energy Marketing, Inc., Concord Energy, LLC and DCP Midstream, LP, represented 37%, 36% and 27%, respectively. As of December 31, 2014, this Partnership had three customers representing 10% or more of the accounts receivable balance: Concord Energy, LLC, DCP Midstream, LP and Suncor Energy Marketing, Inc., represented 58%, 27% and 15%, respectively.

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



	Year ended December 31,
Major Customer	2015	2014
Concord Energy, LLC	45%	23%
Suncor Energy Marketing, Inc.	29%	53%
DCP Midstream, LP	26%	24%

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NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 5 - ASSET RETIREMENT OBLIGATIONS

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



	Year Ended December 31,
	2015			2014

Balance at beginning of period	$	1,702,926		$	935,813
Revisions in estimated cash flows	482,094			693,320
Accretion expense	128,663			73,793
Balance at end of period	2,313,683			1,702,926
Less current portion	(230,000		)	—
Long-term portion	$	2,083,683		$	1,702,926

This Partnership's estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2015, the credit-adjusted risk-free rates used to discount this Partnership's plugging and abandonment liabilities ranged from 7.6% to 8.0%. In periods subsequent to initial measurement of the liability, this Partnership must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors and changes to this Partnership's credit-adjusted risk-free rate as market conditions warrant.

The revisions in estimated cash flows during 2015 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells, as well as a decrease in the estimated useful life of these wells. The current portion of the asset retirement obligations relates to wells that are producing minimal or no hydrocarbons and are expected to be plugged and abandoned within the next 12 months. The revision in the asset retirement obligation did not have an immediate effect in the 2015 statement of operations as the increase in the revised obligation was offset by a capitalized amount, which will be depreciated over the useful lives of respective wells.

The revisions in estimated cash flows during 2014 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain wells, as well as a decrease in the estimated useful life of these wells. The increase in estimated costs is primarily the result of various recent federal, state and local laws that regulate plugging operations and techniques. The revision in the asset retirement obligation did not have an immediate effect in the 2014 statement of operations as the increase in the revised obligation was offset by a capitalized amount, which will be depreciated over the useful lives of respective wells.

NOTE 6 - COMMITMENTS AND CONTINGENCIES

Legal Proceedings

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

Environmental

Due to the nature of the oil and gas industry, this Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in this Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be

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NOTES TO FINANCIAL STATEMENTS - Continued

reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews.

As of December 31, 2015, this Partnership had accrued environmental remediation liabilities of $1,600, which is included in accounts payable and accrued expenses on the balance sheet. This Partnership had no liabilities for environmental remediation efforts as of December 31, 2014.

The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2015 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.

In August 2015, the Managing General Partner received a Clean Air Act Section 114 Information Request (the "Information Request") from the United States Environmental Protection Agency ("EPA"). The Information Request seeks, among other things, information related to the design, operation, and maintenance of certain production facilities in the DJ Basin of Colorado. The Information Request focuses primarily on 46 production facilities, of which two relate to this Partnership, and asks that the Managing General Partner conduct certain sampling and analyses at the identified 46 facilities. The Managing General Partner responded to the Information Request in January 2016. The Managing General Partner cannot predict the outcome of this matter at this time.

NOTE 7 - PARTNERS' EQUITY AND CASH DISTRIBUTIONS

Partners' Equity

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

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



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

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


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


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

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NOTES TO FINANCIAL STATEMENTS - Continued

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 partnership” or result in the termination of this Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis.

Cash Distributions

The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly. Historically, the Managing General Partner has made distributions of Partnership cash on a monthly basis, if funds have been available for distribution. Beginning in the second quarter of 2015, the frequency of cash distributions, if any, was changed to a quarterly basis. The Managing General Partner makes cash distributions of 63% to the Investor Partners and 37% to the Managing General Partner. Cash distributions began in May 2008. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:



	Year Ended December 31,
	2015		2014

Cash distributions	$	534,304	$	2,452,257

NOTE 8 - TRANSACTIONS WITH MANAGING GENERAL PARTNER

The Managing General Partner transacts business on behalf of this Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received by the Managing General Partner on behalf of this Partnership are distributed to the partners, net of corresponding operating costs and other cash outflows incurred on behalf of this Partnership.

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



	As of December 31,
	2015			2014
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	123,519		$	219,542
Other ⁽¹⁾	(359,808		)	(397,692		)
Total Due to Managing General Partner-other, net	$	(236,289	)	$	(178,150	)


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

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NOTES TO FINANCIAL STATEMENTS - Continued

The following table presents Partnership transactions with the Managing General Partner for the years ended December 31, 2015 and 2014. “Well operations and maintenance” are included in the “Crude oil, natural gas and NGLs production costs” line item on the statements of operations.



	Year Ended December 31,
	2015		2014
Well operations and maintenance (1)	$	1,076,301	$	836,856
Direct costs - general and administrative (2)	163,971		171,338
Cash distributions (3)	205,377		929,282

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

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

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

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

The well operating, or well tending, charges cover all normal and regularly recurring operating expenses for the production, delivery and sale of crude oil, natural gas and NGLs, such as:


•	well tending, routine maintenance and adjustment;


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


•	preparing production related reports to this Partnership and government agencies.

The well supervision fees do not include costs and expenses related to:


•	the purchase or repairs of equipment, materials or third-party services;


•	the cost of compression and third-party gathering services, or gathering costs;


•	brine disposal; or


•	rebuilding of access roads.

These costs are charged at the invoice cost of the materials purchased or the third-party services performed.

Lease operating supplies and maintenance expense. The Managing General Partner may enter into other transactions with this Partnership for services, supplies and equipment during the production phase of this Partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.

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

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NOTES TO FINANCIAL STATEMENTS - Continued

(3) The Agreement provides for the allocation of cash distributions 63% to the Investors Partners and 37% to the Managing General Partner. The Investor Partner cash distributions during the years ended December 31, 2015 and 2014 include $7,684 and $21,947, respectively, related to equity cash distributions for Investor Partner units that have been repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 7, Partners’ Equity and Cash Distributions.

NOTE 9 - IMPAIRMENT OF CRUDE OIL AND NATURAL GAS PROPERTIES

In 2015, this Partnership recognized an impairment charge of approximately $4.6 million to write-down certain capitalized well costs on its proved crude oil and natural gas properties. The impairment charge represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value of approximately $1.4 million, excluding estimated salvage value of $0.5 million, was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and future crude oil and natural gas prices which the Managing General Partner reasonably expects this Partnership's crude oil and natural gas will be sold and decreased reserve quantities.

In 2014, this Partnership recognized an impairment charge of approximately $15.8 million to write-down certain capitalized well costs on its proved crude oil and natural gas properties. The impairment charge represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value, and was therefore not recoverable. The estimated fair value of approximately $5.5 million, excluding estimated salvage value of $1.3 million, was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and future crude oil and natural gas prices which the Managing General Partner reasonably expects this Partnership's crude oil and natural gas will be sold and decreased reserve quantities.

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited

Net Proved Reserves

All of this Partnership's crude oil, natural gas and NGLs reserves are located in the U.S. This Partnership utilized the services of an independent petroleum engineer to estimate this Partnership's 2015 and 2014 crude oil, natural gas and NGLs reserves. As of December 31, 2015 and 2014 all of this Partnership's estimates of proved reserves were based on reserve reports prepared by Ryder Scott Company, L.P. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. This Partnership's net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of crude oil, natural gas and NGLs expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development. As of December 31, 2015 and 2014, there are no proved undeveloped reserves for this Partnership.

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



	Price Used to Estimate Reserves (1)
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2015	$	42.07	$	2.09	$	10.02
2014	84.33		3.92		25.53

(1)

The prices used to estimate reserves have been prepared in accordance with SEC commodity prices. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to this Partnership's year-end estimated proved reserves. Prices for each of the two years were adjusted for Btu content, transportation and regional price differences.

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited

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



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

Proved reserves, January 1, 2014	4,716		499		668		1,953
Revisions of previous estimates and reclassifications	(1,285	)	(100	)	(180	)	(494	)
Production	(132	)	(17	)	(33	)	(72	)
Proved reserves, December 31, 2014	3,299		382		455		1,387

Revisions of previous estimates and reclassifications	(2,673	)	(307	)	(316	)	(1,069	)
Production	(139	)	(17	)	(32	)	(72	)
Proved reserves, December 31, 2015	487		58		107		246


Proved Developed Reserves, as of:

December 31, 2014	3,299		382		455		1,387
December 31, 2015	487		58		107		246

2015 Activity. As of December 31, 2015, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 1,069 MBoe. The revision includes downward revisions to previous estimates of 2,673 MMcf of natural gas, 307 MBbl of NGLs and 316 MBbl of crude oil. The downward revisions were the result of the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report and the removal of vertical re-fracs and re-completions from the proved developed reserves, due to the current depressed commodity price environment. There were no proved undeveloped reserves developed in 2015 and no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2015.

2014 Activity. As of December 31, 2014, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 494 MBoe. The revision includes downward revisions to previous estimates of 1,285 MMcf of natural gas, 100 MBbl of NGLs and 180 MBbl of crude oil. The downward revisions were the result of reduced asset performance. There were no proved undeveloped reserves developed in 2014 and no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2014.

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

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

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

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

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited



	As of December 31,
	2015			2014
Leasehold costs	$	95,720		$	509,093
Development costs (1)	3,723,747			15,152,180
Crude oil and natural gas properties, successful efforts method, at cost	3,819,467			15,661,273
Less: Accumulated DD&A	(1,889,887		)	(8,836,596		)
Crude oil and natural gas properties, net	$	1,929,580		$	6,824,677


⁽¹⁾	Includes estimated costs associated with this Partnership's asset retirement obligations. See Note 5, Asset Retirement Obligations, for further information.

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. Substantially all of the $68,000 investment in 2015 was for equipment and services. There were $252,000 in investments for this Partnership in 2014, also primarily for equipment and services.

This Partnership recorded an impairment charge of $4.6 million and $15.8 million for the year ended December 31, 2015 and 2014, respectively. Accordingly, this Partnership reduced crude oil and natural gas properties by $12.4 million and $41.1 million as of December 31, 2015 and 2014, respectively, and related accumulated depreciation, depletion and amortization for those properties by $7.8 million and $25.3 million as of December 31, 2015 and 2014, respectively. See Note 9, Impairment of Crude Oil and Natural Gas Properties, for additional disclosure related to this Partnership's proved property impairments.

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

FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

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

(a) Evaluation of Disclosure Controls and Procedures

As of December 31, 2015, PDC, as Managing General Partner on behalf of this Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of this Partnership's disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that this Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, and that such information is accumulated and communicated to this Partnership's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.

Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and the Chief Financial Officer concluded that this Partnership's disclosure controls and procedures were effective as of December 31, 2015.

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

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


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


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


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

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

Management of the Managing General Partner has assessed the effectiveness of this Partnership's internal control over financial reporting as of December 31, 2015, 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, 2015.

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.

During the three months ended December 31, 2015, PDC, the Managing General Partner, made no changes in this Partnership's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect this Partnership's internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

This Partnership has no employees of its own and has authorized the Managing General Partner to manage this Partnership's business through the D&O Agreement. PDC's directors and executive officers and other key employees receive direct remuneration, compensation or reimbursement solely from PDC, and not this Partnership, with respect to services rendered in their capacity to act on behalf of this Partnership.

Board Management and Risk Oversight

PDC, a publicly traded Delaware corporation, was organized in Nevada in 1955 and reincorporated to Delaware in 2015. 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 PDC Board of Directors, in accordance with Delaware 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 2007 Limited Partnership at this time and no such transactions to repurchase PDC sponsored drilling partnerships have been consummated by the Managing General Partner since 2011.

Managing General Partner Duties and Resource Allocation

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


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


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


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

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

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

Section 16(a) Beneficial Ownership Reporting Compliance

During the fiscal year ended December 31, 2015, no person subject to the requirements of Section 16(a) under the Securities Exchange Act of 1934 failed to file a report required thereunder.

PDC Energy, Inc.

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



Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires

Barton R. Brookman, Jr.	53	President, Chief Executive Officer and Director	2015	2018

Gysle R. Shellum	64	Chief Financial Officer	—	—

Lance Lauck	53	Executive Vice President Corporate Development and Strategy	—	—

Scott J. Reasoner	54	Senior Vice President, Operations

Daniel W. Amidon	55	Senior Vice President, General Counsel and Secretary	—	—

Jeffrey C. Swoveland	61	Non-Executive Chairman	1991	2017

Joseph E. Casabona	72	Director	2007	2017

Anthony J. Crisafio	63	Director	2006	2018

Larry F. Mazza	55	Director	2007	2016

David C. Parke	49	Director	2003	2017

James M. Trimble	67	Director	2010	2016

Kimberly Luff Wakim	58	Director	2003	2018

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. EnLink Midstream LLC 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. In October 2015, Mr. Shellum announced that he would retire effective June 30, 2016.

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).

With the exception of Mr. Reasoner, each of the above 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. Mr. Reasoner became a Named Executive Officer effective January 1, 2015.

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 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. Cristafio is currently the part-time Chief Financial Officer for Tryfoods Manufacturing Inc., from November 2015 to present. 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 LLP, 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.

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 PDC's 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 the Company from June 2011 through June 2014, and continued to serve as the Company'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). Mr. Trimble was an officer of the Company in September 2013, when each of twelve partnerships for which the Company was the managing general partner filed for bankruptcy in the federal bankruptcy court, Northern District of Texas, Dallas Division.

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 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 Certified Public Accounts for more than 20 years.

Audit Committee

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

Other

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.

ITEM 11. EXECUTIVE COMPENSATION

This Partnership does not have any employees or executives of its own. None of PDC's officers or directors receive any direct remuneration, compensation or reimbursement from this Partnership. These persons receive compensation solely from PDC. The Managing General Partner does not believe that PDC's executive and non-executive compensation structure, available to officers or directors who act on behalf of this Partnership, is reasonably likely to have a materially adverse effect on this Partnership's operations or conduct of PDC when carrying out duties and responsibilities to this Partnership, as Managing General Partner under the Agreement, or as operator under the D&O Agreement. The management fee and other amounts paid to the Managing General Partner by this Partnership are not used to directly compensate or reimburse PDC's officers or directors. No management fee was paid to PDC in 2015 or 2014 as this Partnership is not required to pay a management fee other than a one-time fee paid in the initial year of formation per the Agreement. This Partnership pays a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $100 per well per month for Partnership related general and administrative expenses that include accounting, engineering and management of this Partnership by the Managing General Partner. See Item 13, Certain Relationships and Related Transactions and Director Independence, for a discussion of compensation paid by this Partnership to the Managing General Partner.

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

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

RELATED STOCKHOLDER MATTERS

The following table presents information as of December 31, 2015, concerning the Managing General Partner's interest in this Partnership and other persons known by this Partnership to own beneficially more than 5% of the interests in this Partnership. Each partner exercises sole voting and investing power with respect to the interest beneficially owned.



	Limited Partnership Units
	Number of	Number of Units Beneficially Owned	Percentage of Total Units Outstanding		Percentage of
	Units				Total Partnership
	Outstanding Which				Interests
	Represent 63% of Total				Beneficially
Person or Group	Partnership Interests (1)				Owned
	4,470.00
PDC Energy, Inc. (2) (3) (4) (5)	—	129.1	2.89	%	1.82	%


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


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


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


(4)	The percentage of “Total Partnership Interests Beneficially Owned” by PDC with respect to its limited partnership units repurchased is determined by multiplying the percentage of limited partnership units repurchased by PDC to total limited partnership units, by the limited partners' percentage ownership in this Partnership. [(129.1 units/4,470 units)*63% limited partnership ownership]


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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR

INDEPENDENCE

Compensation to the Managing General Partner

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

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


•	Petroleum engineers who plan and direct PDC's well completions and recompletions, construct and operate PDC's well and gathering lines and manage PDC's production operations;


•	Petroleum reserve engineers who evaluate well reserves at least annually and monitor individual well performance against expectations; and


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

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

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

See Note 8, Transactions with Managing General Partner, to the financial statements included elsewhere in this report for information regarding compensation to and transactions with the Managing General Partner.

Related Party Transaction Policies and Approval

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

Director Independence

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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



	Year Ended December 31,
Type of Service	2015		2014
Audit Fees (1)	$	140,000	$	140,000


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

Audit Committee Pre-Approval Policies and Procedures

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

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The index to Financial Statements is located on page 26.

(b) Exhibits index.

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

3.1

Limited Partnership Agreement

10-12G/A Amend 1

000-53201

08/06/2008

3.2

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

10-12G/A Amend 1

000-53201

3.1

08/06/2008

10.1

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

10-12G/A Amend 1

000-53201

10.2

08/06/2008

10.2

Form of assignment of leases to this Partnership

10-12G/A Amend 1

000-53201

10.1

08/06/2008

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(a) 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(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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.

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

99.1

Report of Independent Petroleum Consultants - Ryder Scott Company, LP

99.2

Audited Consolidated Financial Statements for the year ended December 31, 2015 of PDC Energy, Inc. and its subsidiaries, as Managing General Partner of this Partnership

10-K

000-07246

02/22/16

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.

SIGNATURES

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

Rockies Region 2007 Limited Partnership

By its Managing General Partner

PDC Energy, Inc.



	By: /s/ Barton R. Brookman, Jr.
	Barton R. Brookman, Jr. President, Chief Executive Officer and Director of PDC Energy, Inc.
	March 25, 2016

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



Signature	Title	Date
/s/ Barton R. Brookman, Jr.	President, Chief Executive Officer and Director	March 25, 2016
Barton R. Brookman, Jr.	PDC Energy, Inc. Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	March 25, 2016
Gysle R. Shellum	PDC Energy, Inc. Managing General Partner of the Registrant
	(Principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	March 25, 2016
R. Scott Meyers	PDC Energy, Inc. Managing General Partner of the Registrant
	(Principal accounting officer)

/s/ Jeffrey C. Swoveland	Chairman and Director	March 25, 2016
Jeffrey C. Swoveland	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Joseph E. Casabona	Director	March 25, 2016
Joseph E. Casabona	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Anthony J. Crisafio	Director	March 25, 2016
Anthony J. Crisafio	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Larry F. Mazza	Director	March 25, 2016
Larry F. Mazza	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Kimberly Luff Wakim	Director	March 25, 2016
Kimberly Luff Wakim	PDC Energy, Inc.
	Managing General Partner of the Registrant

ROCKIES REGION 2007 LP - FORM 10-K - March 25, 2016

Attached files

ROCKIES REGION 2007 LP Reports