Rockies Region 2006 Limited Partnership - FORM 10-K

Attached files

file	filename
EX-32.1 - 906 CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - Rockies Region 2006 Limited Partnership	rr06-ex321_20161231.htm
EX-99.1 - REPORT OF INDEPENDENT PETROLEUM CONSULTANTS - RYDER SCOTT COMPANY, L.P. - Rockies Region 2006 Limited Partnership	rr06-ex991_20161231.htm
EX-31.2 - 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - Rockies Region 2006 Limited Partnership	rr06-ex312_20161231.htm
EX-31.1 - 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - Rockies Region 2006 Limited Partnership	rr06-ex311_20161231.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, 2016

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

FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-52787

Rockies Region 2006 Limited Partnership

(Exact name of registrant as specified in its charter)



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

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

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

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

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



	Title of Each Class
	Limited Partnership Interests

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

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

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

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

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

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



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

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

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

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

As of March 15, 2017, this Partnership had 4,497.03 units of limited partnership interest and no units of additional general partnership interest outstanding.

Rockies Region 2006 Limited Partnership

2016 Annual Report on Form 10-K

Table of Contents



		Page
	Part I
Item 1	Business	3
Item 1A	Risk Factors	15
Item 1B	Unresolved Staff Comments	15
Item 2	Properties	15
Item 3	Legal Proceedings	15
Item 4	Mine Safety Disclosures	15

	Part II
Item 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6	Selected Financial Data	17
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	18
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	25
Item 8	Financial Statements and Supplementary Data	26
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	46
Item 9A	Controls and Procedures	46
Item 9B	Other Information	46

	Part III
Item 10	Directors, Executive Officers and Corporate Governance	47
Item 11	Executive Compensation	51
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	51
Item 13	Certain Relationships and Related Transactions and Director Independence	52
Item 14	Principal Accountant Fees and Services	53

	Part IV
Item 15	Exhibits, Financial Statement Schedules	54
Item 16	Form 10-K Summary	56

Signatures		57

PART I

WHERE YOU CAN FIND ADDITIONAL INFORMATION

The Rockies Region 2006 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 0001376912. You can read and copy any materials this Partnership files with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., 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 or NGLs equals six Mcf of natural gas.

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.

NGLs - Natural gas liquids.

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: reserves, production, sales, cash flows and liquidity; anticipated capital expenditures and costs; midstream capacity and related curtailments; 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. Forward-looking statements are always 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:


•	availability of future cash flows to enable this Partnership to continue as a going concern, for investor distributions, or funding of development activities;


•	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;


•	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 wells being greater than expected;


•	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 and local capacity, on the prices this Partnership receives for its production;


•	the effect of operating pressures from pipelines, gathering and transportation facilities that influence the ability for a well to produce against such pressures;


•	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 2006 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”) and the Managing General Partner. The Investor Partners own 63 percent of this Partnership's capital or equity interests (which are sometimes referred to as Investor Partner units). PDC, a Delaware corporation, is the Managing General Partner and owns a 37 percent general partnership interest in this Partnership. 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 all of the capital raised in the offering for the initial drilling and completion of the wells in which this Partnership participated.

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 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 as this Partnership's wells are depleted or become uneconomical to produce, at which time the wells may be sold or plugged, reclaimed, and abandoned. This Partnership's maximum term of existence extends through December 31, 2056, unless dissolved in certain circumstances stipulated in the Agreement, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

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.

Going Concern

Because of projected negative cash flows, there is substantial doubt about this Partnership's ability to continue as a going concern.

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 this Partnership's remaining productive wells. For wells not currently producing, the Managing General Partner is in the process of reviewing the circumstances surrounding the lack of production and has begun plugging wells which are not expected to be economical to restore to production, or that have been deemed not capable of production, in order to minimize future additional costs associated with shut-in wells. For wells that are not currently producing, but are expected to be economical to restore, workovers may be performed to return those wells to production.

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 customary 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. 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 and reasonably foreseeable for future plugging and abandonment activities. 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. Additionally, as the wells have gotten older and the likelihood of plugging and abandonment activities are more likely to occur in the foreseeable future, the Managing General Partner, as allowed in the Partnership Agreement, beginning in first quarter of 2017, has elected to suspend cash distributions to cover the costs of necessary plugging and abandonment activities. Based on current economic conditions, it appears likely that the costs of plugging and abandonment operations will exceed available cash and earnings from this Partnership. This Partnership has not historically been charged interest by PDC, although PDC is entitled to collect interest per the terms of the Partnership Agreement.

Area of Operations

Wattenberg Field, Denver-Julesburg Basin, Colorado. This Partnership operates exclusively in the Wattenberg Field, located northeast of Denver, Colorado. Its 59 vertical wells in this field exhibit production histories typical for other vertical wells located in this field, with an initial high production rate following completion and relatively rapid decline, followed by relatively lower rates of decline and production levels throughout the well's remaining life. All of the producing wells in which this Partnership has an ownership interest are in the stage of lower rates of decline and lower production levels, exhibited by wells that are towards the end of their economic life. All of this Partnership's crude oil, natural gas, and/or NGLs production is located in the Wattenberg Field, making this Partnership vulnerable to risks associated with operating in a single geographical area. This Partnership’s 59 vertical wells were all drilled in the Codell formation, with 10 also completed in the shallower Niobrara formation. This Partnership's wells in this area are generally 6,500 to 7,500 feet deep. Over the years, numerous vertical wells within the Wattenberg Field have been shut-in as a result of increased gathering system line pressures, decreases in the estimated value of future cash flows of the wells exceeding the natural production pressure of the wells, issues from hydraulic fracturing of nearby horizontal wells, or well bore mechanical testing. Currently, 38 of this Partnership's 59 wells are shut-in.

Because the remaining producing wells owned by this Partnership are dispersed over a large geographic area, the wells are particularly sensitive to the operating pressures of the gathering facilities connected to the individual wells. To the extent the relative differential pressure of the well exceeds the pressures of of the gathering system, the wells will continue to produce, although the value of the production may not exceed the operating costs. The wells benefit from decreases in system line pressures and are negatively affected by higher system pressures. Because the system is connected to many other non-Partnership wells, and the third-party gathering system is optimized for the system as a whole, this Partnership's wells are affected in ways that limit the Managing General Partner's ability to significantly influence individual well performance. For example, 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 this Partnership's service provider, DCP Midstream, LP ("DCP"), completed its Grand Parkway gas gathering project. The production from wells owned by this Partnership increased in 2015 and 2016 from respective prior years as a result of this pressure effect, offsetting the normal decline of the well performance. However, the relatively lower commodity prices in recent years 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. The Managing General Partner and other producers in the field are working with the service provider to assist in developing plans for additional facilities, with the earliest such facilities scheduled to begin service in late 2018. Prior to the addition of new facilities, line pressures may significantly increase which may lead to older, lower pressure wells losing or significantly reducing the ability to produce. The result of this line pressure reduction is that the 2016 production from this Partnership increased to 33,087 Boe compared to 29,505 Boe produced in 2015, reflecting the net operational result of the gathering system pressure improvement and the natural decline rates of this Partnership's wells.

Title to Properties

This Partnership owns a direct working 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. The Managing General Partner is not aware of any 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 well bore working interest in in each of 59 wells. This Partnership originally drilled 97 gross wells (95.7 net) (the net number representing the number of gross wells, multiplied by the working interest in the wells owned by this Partnership) during drilling operations that began immediately after funding and drilling operations concluded in August 2007 when the last well was connected to sales and gathering lines. Of the 97 gross wells drilled, 91 were productive. No additional development activity has occurred since 2007. This Partnership's 91 gross productive wells included 86 gross (85.2 net) wells located in Colorado and five gross (4.5 net) wells located in North Dakota. This Partnership's 23 Piceance Basin and five North Dakota wells were divested in June 2013 and February 2011, respectively and the majority of the proceeds were distributed from this Partnership shortly thereafter. This Partnership plugged and abandoned four wells in 2016 and expects to plug and abandon an additional 15 to 20 wells during 2017 as the operating and future required capital are expected to result in uneconomic results for these wells. The 97 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, 2016 and 2015:



	Productive Natural Gas Wells
	2016		2015
Location	Gross	Net	Gross	Net

Wattenberg Field	59.0	58.9	63.0	62.9

Although the wells included above produced hydrocarbons during 2016, as of December 31, 2016, 38 of the 59 Partnership's productive wells were shut-in for various reasons including production equipment failures, environmental protection requirements, well bore integrity testing for nearby horizontal wells, and to build up well head pressure to overcome line pressures.

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, 2016, 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 to determine and report 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 40 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 2016 reserve estimates. The SEC has established that pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of month prices for the preceding 12 months. The New York Mercantile Exchange ("NYMEX") prices used in preparing the reserves are then adjusted by the required adjustments related to energy content, location and basis differentials, and other marketing deductions to arrive at the net realized price. The SEC NYMEX prices used in the preparation of reserves are as follows:



As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2016	$	42.75	$	2.48	$	42.75
2015	50.28		2.58		50.28

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, 2016 and 2015, 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,
	2016	2015
Proved Reserves
Natural Gas (MMcf)	210	133
Crude Oil and Condensate (MBbl)	45	40
NGLs (MBbl)	29	19
Total proved reserves (MBoe)	110	82

The increase in proved reserves as of December 31, 2016, compared to December 31, 2015 was mainly due to reductions in gathering system line pressures, which has enhanced the production profile of some of this Partnership's wells. Proved reserves could be negatively impacted by increased gathering system line pressures in the future. Although this Partnership had an increase in proved reserves from December 31, 2015 to December 31, 2016, the future estimated undiscounted operating cash flows were a negative $2.3 million at December 31, 2016. The value, based upon SEC reserve rules, is negative based on the inclusion of costs associated with the plugging and abandonment of this Partnership's wells. As a result of the above plugging and abandonment costs exceeding the future estimated undiscounted cash flows, the Managing General Partner has elected to suspend cash distributions from this Partnership beginning in the first quarter of 2017.

Production, Sales, Prices and Production Costs

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



	Year Ended December 31,
	2016		2015
Production

Crude Oil (Bbl)	16,176		15,977
Natural gas (Mcf)	55,582		44,415
NGLs (Bbl)	7,647		6,125
Crude oil equivalent (Boe)	33,087		29,505

Crude Oil, Natural Gas and NGLs Sales

Crude oil	$	635,274	$	621,792
Natural gas	101,499		96,397
NGLs	88,498		61,320
Total crude oil, natural gas and NGLs sales	$	825,271	$	779,509

Average Net Realized Sales Price

Crude Oil (per Bbl)	$	39.27	$	38.92
Natural gas (per Mcf)	1.83		2.17
NGLs (per Bbl)	11.57		10.01
Crude oil equivalent (per Boe)	$	24.94	$	26.42

Average Costs and Expenses (per Boe)
Lease operating costs	$	17.92	$	21.15
Production taxes	$	1.07	0.87
Transportation costs	$	—	0.31
Total production cost	$	18.99	$	22.33

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 as wells as general and administrative costs, depreciation, depletion and amortization expenses, and impairments, 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 as these services are covered by the monthly well operating charge paid by this Partnership to PDC. This Partnership's most significant customers are currently Suncor Energy Marketing, Inc. and DCP. Sales to these parties represented 67 percent and 23 percent, respectively, of this Partnership's 2016 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. Since this Partnership does not refine any of its crude oil production, the crude oil is sold to companies that either transport or resell the commodity, or process the crude oil in their own facilities. Title to the crude oil transfers at the time the crude oil leaves this Partnership's well site and is placed in a truck. 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 a midstream service provider. The Managing General Partner generally sells the natural gas that this Partnership produces under contracts with indexed Colorado Interstate Gas ("CIG") monthly 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. This Partnership's NGLs sales are priced based upon the components of the product and are correlated to the price of crude oil. 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 and NGLs are transported through third-party gathering systems and pipelines and this Partnership incurs processing, gathering and transportation costs to move this Partnership's natural gas and NGLs. These costs vary based upon the volume and distance shipped, as well as the fee charged by the third-party processor or transporter. 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, from time to time, the crude oil is transported through the White Cliffs Pipeline, LLC ("White Cliffs") crude oil pipeline for redelivery to a sales point in Cushing, Oklahoma.

Transportation and gathering costs affect this Partnership's crude oil, natural gas, and NGLs sales and such transactions 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 its sales pursuant to which the transportation and/or processing is provided by or through the purchaser. The net-back method results in the recognition of a sales price that is below the indices for which the product is based. This Partnership uses the gross method of accounting for crude oil delivered through the White Cliffs pipeline as the purchaser does not provide transportation, gathering or processing. Under this method, this Partnership recognizes revenues based on the gross selling price and records transportation, gathering and processing charges as a component of production costs. This Partnership did not transport any crude oil through White Cliffs in 2016; however, it may do so in future periods.

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 Exploration and 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. Additionally, other regulated matters include:


•	bond requirements in order to operate wells;


•	well bore integrity testing;


•	drilling and casing methods;


•	surface use and restoration of well properties;


•	well plugging and abandoning;


•	fluid disposal; and


•	air emissions.

Regulation of Transportation of Natural Gas. This Partnership 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. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 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. This Partnership cannot

determine to what extent its future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels.

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. In addition, the change in the administration under the Executive Branch of the federal government may result in change or uncertainty with respect to the future regulatory environment affecting the oil and natural gas industry. This uncertainty may affect how this Partnership’s industry is regulated as well as the level of public interest in environmental protection and may result in new or different pressures being exerted. For example, public interest groups may increase their use of litigation as a means to continue to exert pressure on the oil and natural gas industry. Accordingly, while this Partnership expects regulatory and enforcement pressures on its business to continue at federal, state, and local levels, the nature, level, and source of such pressures may change.

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

The White House Council on Environmental Quality continues to coordinate an administration-wide review of hydraulic fracturing. The EPA released the final report "Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources" on December 12, 2016. The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances - including surface spills, injection of fluids into wells with inadequate integrity, discharge of untreated or inadequately treated wastewater, and disposal or storage in unlined pits. 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, 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.

The state in which this Partnership operates, Colorado, has adopted regulations regarding permitting, transparency, and well construction requirements with respect to hydraulic fracturing operations, and disposal well rules focused on potential seismicity concerns and may in the future adopt additional regulations or otherwise seek to ban fracturing or disposal 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. 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 ("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.

In Colorado, local governing bodies have issued drilling moratoriums, developed jurisdictional siting, permitting and operating requirements, and conducted 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 Colorado cities of Boulder, Lafayette, Fort Collins and Brighton passed hydraulic fracturing bans. 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 future fracturing activities, if any, to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of hydrocarbons, may preclude its ability to drill wells. 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 or leases numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. Although this Partnership believes that it has generally 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 leases 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), remediate property contamination (including surface and groundwater contamination), or 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, transported, 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 laws, 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 to develop regulations to implement these requirements. This Partnership may be required to incur certain capital investments 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 and amendments to such standards ("NSPS OOOO” and “NSPS OOOOa”) became effective between 2012 and 2016, and have added administrative and operational costs. In addition, 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 equally or more stringent than NSPS OOOO / NPS OOOOa and directly regulate methane emissions from affected facilities. In October 2015, the EPA reduced the ozone compliance levels under 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. In October 2016, Colorado submitted revisions to its ozone SIP to meet requirements caused by an increase in ozone non-attainment status to “moderate” from “marginal.”

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 load out 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 clarifying 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 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 2016 finalized a rule to alter how it identifies critical habitat for endangered and threatened species.

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. In addition to SPCC requirements, 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 2017 and beyond. Environmental regulations have increased this Partnership’s costs and planning time, but have had no materially adverse effect on its 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.

In August 2015, the Managing General Partner received an Information Request from the EPA. The Information Request sought, among other things, information related to the design, operation, and maintenance of the Managing General Partner's Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focused on historical operation and design information for 46 of the Managing General Partner's production facilities and asks that it conduct sampling and analyses at the identified 46 facilities. These 46 facilities include four of this Partnership's wells. The Managing General Partner responded to the Information Request in January 2016. Throughout 2016, it continued to meet with the EPA, U.S. Department of Justice, and Colorado Department of Public Health and Environment, and in December 2016 it received a draft consent decree from the EPA.

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 Wattenberg Field production facilities consistent with applicable standards under Colorado law. These 65 facilities include four of this Partnership's wells. These four Partnership wells are the same wells identified in the EPA Information Request noted in the previous paragraph This matter has been combined with the matter discussed above. The ultimate outcome related to these combined actions has not been determined 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 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, was granted authority by the Investor Partners to manage this Partnership's activities through the D&O Agreement. Such responsibility required PDC to utilize 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 operations aspect of the wells. PDC's administrative staff controls this Partnership's finances and makes distributions, apportions costs and revenues among wells, and prepares Partnership reports, SEC filings, tax reports, and financial statements 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 market 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 percent 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 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, finance, 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 the 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 subject to market sensitive contracts, the price of which increases or decreases with market forces beyond the control of PDC and 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

From time to time, this Partnership is a party to various legal proceedings in the ordinary course of business. This Partnership is not currently subject to any material pending legal proceedings.

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 Wattenberg Field production facilities consistent with applicable standards under Colorado law. These 65 facilities include four of this Partnership's wells. These four Partnership wells are the same wells identified in the EPA Information Request noted in the previous paragraph. This matter has been combined with the matter discussed above. The ultimate outcome related to these combined actions has not been determined at this time.

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, 2016, this Partnership had 1,975 Investor Partners holding 4,497.03 units and one Managing General Partner. The investments held by the Investor Partners are in the form of limited partnership interests. Investor Partners' interests are transferable; however, no assignee of units in this Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. Through December 31, 2016, the Managing General Partner has repurchased 163.8 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 distributed cash on a monthly basis, if funds were available for distribution. Beginning in the second quarter of 2015, the frequency of cash distributions was changed to a quarterly basis; however, this Partnership has made no cash distributions since the first quarter of 2015 as cash flows from this Partnership's operations were negative and this Partnership currently has outstanding payables to the Managing General Partner. If available, PDC will make cash distributions of 63 percent of cash available for distributions to the Investor Partners, including any Investor Partner units purchased by the Managing General Partner, and 37 percent of cash available for distributions to the Managing General Partner throughout the term of this Partnership. As the wells have gotten older and the likelihood of plugging and abandonment activities in the foreseeable future has increased, the Managing General Partner, as allowed in the Partnership Agreement, beginning in the first quarter of 2017, has elected to suspend cash distributions to cover the costs of necessary plugging and abandonment activities. Based on current economic conditions, it appears likely that the costs of plugging and abandonment operations will exceed available cash and earnings from this Partnership. As a result of the impact to the cash distribution policy, if cash were to become available in excess of the plugging and abandonment activities, the Managing General Partner would likely hold cash distributions until the current asset retirement obligations are significantly reduced. Because of projected negative cash flows, there is substantial doubt about this Partnership's ability to continue as a going concern.

Cash is 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. 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 laws, and agreements.

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, including consideration of future plugging and abandonment expenditures. 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.

The following table presents the capital contributions that were initially contributed by the General Partner and the Investor Partners and the distributions made to the General Partner and Investor Partners for the periods indicated:



Period	Contributions (Distributions)

Initial capital contributions, September 7, 2006	$	128,852,869
Distributions, during the year ended December 31, 2016	—
Distributions, during the year ended December 31, 2015	(47,167		)
Distributions, from inception through December 31, 2016	(93,832,266		)

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. Also, production from crude oil and natural gas wells that have been producing for longer periods of time are more susceptible to variations in line pressures attributed to gas gathering. From time to time, this Partnership's production has been adversely affected by high line pressures in the Wattenberg Field. 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 to 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 accordance with the Partnership Agreement, the Managing General Partner has elected to suspend cash distributions, beginning in the first quarter of 2017, in order to fund the plugging and abandonment costs of certain Partnership wells. Since the formula for the repurchase price is set at a minimum of four times the most recent 12 months of cash distributions, due to this Partnership making no cash distributions over the most recent 12 months, the Managing General Partner is unable to repurchase units as there is no value upon which to base the calculation. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10 percent 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 Managing General Partners did not have any limited partner unit repurchases during the three months ended December 31, 2016.

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 increased six percent for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily attributable to the increase in production of 12 percent year over year, partially offset by the decrease in the average sales price per Boe of six percent in 2016 as compared to 2015. The production volume was 33,087 Boe for 2016 compared to 29,505 Boe for 2015 and the average selling price per Boe was $24.94 for the current year compared to $26.42 for 2015. Crude oil, natural gas, and NGLs production costs for the year ended December 31, 2016 decreased by approximately $31,000 compared to 2015 as there were less wells operating during 2016. The decrease in production costs was primarily related to lease operating costs to plug and abandon wells, well swabbing and wireline work, regulatory compliance costs and lift system repairs, partially offset by an increase in metering expense. Crude oil, natural gas, and NGLs production costs per Boe decreased to $18.99 during 2016 from $22.33 in 2015 due to lower production costs and higher volumes.

Beginning in the second quarter of 2015, this Partnership made no quarterly cash distributions to the Managing General Partner or Investor Partners as cash flows from this Partnership's operations were insignificant and this Partnership currently has outstanding payables to the Managing General Partner. Cash distributions were $47,000 in the first quarter of 2015. Suspension of the quarterly cash distributions will continue until such time that cash flows can support the necessary costs of plugging and abandoning the wells that are becoming unproductive or require capital investments that are unsupportable at current commodity prices. Although this Partnership's production increased 12 percent in 2016 as compared to 2015, the crude oil, natural gas, and NGLs commodity prices remained depressed. As a result, the Managing General Partner expects this Partnership to continue to have cash flow deficits from operations for some time.

This Partnership recognized an impairment charge of approximately $4.6 million in 2015 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. The effect of this impairment in 2015 resulted in lower accumulated crude oil and natural gas property net costs; therefore, the depreciation, depletion and amortization expense in 2016 was significantly lower than in 2015.

Production is expected to continue to decline given the natural declines of the wells in this Partnership. When considering the current commodity price environment, coupled with the ongoing operating costs, production taxes, general and administrative costs, as well as the costs expected to be incurred for plugging and abandoning wells, it indicates that this Partnership will not generate positive net cash flows in the foreseeable future. Accordingly, beginning in the first quarter of 2017, this Partnership has suspended distributions until such time as it is clear that this Partnership will have distributable cash in excess of anticipated future plugging and abandonment costs. Because of the projected negative net cash flows, there is substantial doubt about this Partnership’s ability to continue as a going concern.

The Managing General Partner is considering various options to mitigate risks that raise substantial doubt about this Partnership’s ability to continue as a going concern, including, but not limited to, deferral of obligations, continued suspension of distributions to partners, and partial or complete sale of assets. However, there can be no assurance that this Partnership will be able to mitigate such conditions. Failure to do so could result in a partial asset sale or some form of bankruptcy, liquidation, or dissolution of this Partnership.

Results of Operations

Summary Operating Results

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



	Year ended December 31,
	2016		2015		Change
Number of gross productive wells (end of period)	59		63		(6	)%

Production
Crude oil (Bbl)	16,176		15,977		1	%
Natural gas (Mcf)	55,582		44,415		25	%
NGLs (Bbl)	7,647		6,125		25	%
Crude oil equivalent (Boe)	33,087		29,505		12	%
Average Boe production per day	90		81		12	%

Crude oil, natural gas and NGLs sales
Crude oil	$	635,274	$	621,792	2	%
Natural gas	101,499		96,397		5	%
NGLs	88,498		61,320		44	%
Total crude oil, natural gas and NGLs sales	$	825,271	$	779,509	6	%

Average selling price
Crude oil (per Bbl)	$	39.27	$	38.92	1	%
Natural gas (per Mcf)	1.83		2.17		(16	)%
NGLs (Bbl)	11.57		10.01		16	%
Crude oil equivalent (per Boe)	$	24.94	$	26.42	(6	)%

Average Costs and Expenses (per Boe)
Lease operating costs	$	17.92	$	21.15	(15.3	)%
Production taxes	1.07		0.87		23.0	%
Transportation costs	—		0.31		*
Total production cost	$	18.99	$	22.33	(15.0	)%

Depreciation, depletion and amortization	$	6.29	$	12.87	(51	)%

Operating costs and expenses
Total production costs	$	628,457	$	658,989	(5	)%
Direct costs - general and administrative	177,663		163,009		9	%
Depreciation, depletion and amortization	208,200		379,645		(45	)%
Impairment of crude oil and natural gas properties	—		4,611,188		*

Cash distributions	$	—	$	47,167	*

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

Amounts may not recalculate due to rounding.

Crude Oil, Natural Gas, and NGLs Sales

Changes in Crude Oil, Natural Gas, and NGLs Sales Volumes. For 2016 compared to 2015, crude oil, natural gas, and NGLs production, on an energy equivalency-basis, increased 12 percent, primarily driven by a 10 percent reduction in average system line pressures.

Production from crude oil and natural gas wells that have been producing for longer periods of time are more susceptible to variations in line pressure. From time to time, this Partnership’s production has been adversely affected by high line pressures. This Partnership relies on its third-party midstream service provider to construct compression, gathering and processing facilities to keep pace with production growth in the Wattenberg Field. The Managing General Partner, along with other operators in the Wattenberg Field, continues to work closely with the third-party midstream providers to monitor the need for such facilities in an effort to ensure adequate system capacity going forward. The timing and availability of adequate infrastructure, including potential line pressure impacts in 2017, is not within this Partnership’s control and may be affected by a number of factors, including potential increases in production from the Wattenberg Field and warmer than expected weather.

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 and NGLs increased during the second half of 2016 compared to the first half of 2016 based on overall supply and demand fundamentals. The average natural gas price also fluctuated over 2016 based on the impact of declines from U.S. production combined with the effect of weather and consumption.

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, from time to time through 2015, the crude oil is transported through the White Cliffs Pipeline, LLC ("White Cliffs") crude oil pipeline for redelivery to a sales point in Cushing, Oklahoma. The Managing General Partner entered into a long-term commitment with White Cliffs in mid-2015. The cost of trucking or transporting the crude oil to market affects the price this Partnership ultimately receives for the crude oil. This Partnership did not transport any crude oil through White Cliffs in 2016.

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. 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. Under this method, this Partnership recognizes revenues based on the gross selling price.

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 the actual amounts filed 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, 2016 decreased by approximately $31,000 compared to 2015. Crude oil, natural gas, and NGLs production costs for 2016 and 2015 were 76 percent and 85 percent of 2016 and 2015 revenue, respectively. In early 2016, as a result of depressed oil prices, the Managing General Partner instituted a field-wide cost savings program that resulted

in a $31,000 decrease in production expenses in 2016 as compared to 2015. The decreases were largely related to well swabbing and wireline work, regulatory compliance costs and lift system repairs, partially offset by an increase in metering expense and plugging and abandonment costs. The decreases in lease operating costs and transportation were slightly offset by a $10,000 increase in production taxes related to increases in sales and ad valorem mill rates. Crude oil, natural gas, and NGLs production costs per Boe decreased to $18.99 during 2016 from $22.33 in 2015 due to lower production costs and higher volumes.

Direct costs - general and administrative

Direct costs - general and administrative for the year ended December 31, 2016 increased approximately $15,000 compared to 2015, primarily attributable to higher professional services costs.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization ("DD&A") expense decreased approximately $171,000 for the year ended December 31, 2016 compared to 2015, due to a 51 percent decrease in the DD&A expense rate, offset in part by increased production volumes of 12 percent in 2016. The DD&A expense rate per Boe decreased to $6.29 for 2016 compared to $12.87 during 2015, primarily due to the effect of an impairment recorded on proved oil and natural gas properties in 2015. As a result of revisions in estimated cash flows related to asset retirement obligations, this Partnership's DD&A expense rate is expected to increase in 2017 as compared to 2016.

Impairment of Crude Oil and Natural Gas Properties

In 2015, this Partnership recognized impairment charges of approximately $4.6 million to write-down its proved crude oil and natural gas properties, of which $1.3 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, and was therefore not recoverable. The estimated fair value of approximately $479,000, excluding estimated salvage value of $471,000, 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. This Partnership did not recognize any impairment charge in 2016. Further deterioration of commodity prices could result in additional impairment charges to this Partnership's crude oil and natural gas properties.

Asset Retirement Obligations and Accretion Expense

This Partnership plugged and abandoned four wells during 2016 and the Managing General Partner expects that 15 to 20 of this Partnership's wells will be plugged and abandoned in 2017. These wells are expected to be uneconomical to operate given anticipated capital spending that would be required to meet newly-implemented environmental standards. The costs to plug and abandon wells in 2017 is expected to result in a significant cash outflow for this Partnership. To the extent that the costs of plugging and abandonment activities exceed available cash flows generated by this Partnership's operations, the Managing General Partner expects to fund such activities. The Managing General Partner would recover amounts funded from future cash flows of this Partnership, if available. As of December 31, 2016, this Partnership has increased the current portion of its asset retirement obligation liability to $978,000. The wells that are expected to be plugged and abandoned in 2017 experienced a decrease in production totaling 1.1 MBoe in 2016 as compared to 2015, and therefore are not expected to generate positive operating cash flows. Of the remaining 46 wells in this Partnership that operated during 2016, 23 wells had an increase in production totaling approximately 7.2 MBoe in 2016 compared to 2015 and 23 wells had a decrease in production totaling approximately 2.4 MBoe in 2016 compared to 2015.

Changes in accretion of asset retirement obligations ("ARO") expense. ARO expense increased $39,000, or 31 percent, to $166,000 in 2016 compared to $127,000 in 2015, primarily attributable to an increase in asset retirement obligations recorded in December 2015 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. Beginning in the second quarter of 2015 and continuing through 2016, this Partnership made no quarterly cash distributions to the Managing General Partner and Investor Partners.

This Partnership generated no liquidity during the year ended December 31, 2016, as cash flows generated from crude oil, natural gas and NGLs sales were utilized for operating activities, including the plugging and abandonment of four wells, and capital expenditures. Due to the significant decrease in liquidity experienced in 2016 and 2015 and anticipated future expenditures required to remain in compliance with certain regulatory requirements, costs of necessary plugging and abandonment activities, and to satisfy asset retirement obligations, the Managing General Partner believes that projected cash flows from operations will be insufficient to meet this Partnership’s obligations. Commodity prices during the second half of 2016 showed improvement over pricing experienced during the first half of 2016. However, this level of price improvement alone is not likely to be sufficient to alleviate concerns regarding this Partnership’s ability to meet its obligations. To meet such obligations, which total in excess of $1.3 million at December 31, 2016, this Partnership would likely need to continue to experience the production volume improvement seen during 2016 and/or commodity pricing would need to significantly improve over pricing seen during 2016.

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. Given the current commodity price forecast, this Partnership anticipates a net lower annual level of crude oil, natural gas and NGLs production and, therefore, lower revenues. Under these circumstances, decreased production would have a material

adverse impact on this Partnership's operations and, when combined with the requirements to plug and abandon wells, the Managing General Partner has made the decision, beginning in the first quarter of 2017, to suspend distributions from this Partnership, until such time as it is clear that there is net cash available to cover expected costs.

Working Capital

At December 31, 2016, this Partnership had a working capital deficit of $1,177,000, compared to $361,000 at December 31, 2015. The increase in the deficit of $816,000 was primarily due to the following changes:


•	an increase in current asset retirement obligations of $633,000; and


•	an increase in amounts due to Managing General Partner-other, net, of $187,000.

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 as there is no expectation that such borrowings could be repaid. Any such borrowings would be non-recourse to the Investor Partners. The Managing General Partner has recorded an accounts receivable of $322,000 for the amounts due from this Partnership. Partnership borrowings, should any occur, will be non-recourse to the Investor Partners.

Cash Flows

Operating Activities

Net cash flow from operating activities was $7,000 for the year ended December 31, 2016, compared to a net cash flow deficit from operating activities of $6,000 in 2015. The increase of $13,000 in cash from operating activities was primarily attributable to the amount due to the Managing General Partner increasing as this Partnership utilized a portion of its cash flows from operations to fund its capital expenditures. During 2016, this Partnership's liquidity position continued to deteriorate.

In 2017, this Partnership plans to fund its operations from cash flows from operating activities. Greater cash flow would most likely occur from improved commodity pricing and, to a lesser extent, a sustained increase in production. The Managing General Partner is considering various options to maximize this Partnership's liquidity, including, but not limited to, deferral of payment of certain obligations, continued suspension of distributions to partners, and partial or complete sale of assets. However, there can be no assurance that this Partnership will be able to generate sufficient liquidity. Failure to do so could result in a partial asset sale or some form of bankruptcy, liquidation, or dissolution of this Partnership.

Investing Activities

Cash flows from investing activities primarily consist of investments in equipment required on the wells, which may include environmental monitoring equipment required by regulation. 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, 2016, investments in equipment were approximately $9,000 compared to $70,000 in 2015.

Financing Activities

This Partnership initiated monthly cash distributions to investors in May 2007 and has distributed $93.8 million through December 31, 2016. 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 percent general partner interest in this Partnership. Distributions to Investor Partners represent amounts distributed to Investor Partners for their 63 percent 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
2016	$	—	$	—	$	—
2015	17,452		29,715		47,167

Off-Balance Sheet Arrangements

As of December 31, 2016, 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.

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, such as in the determination of reserves, estimates of revenue and expenses and the timing of expenditures related to the plugging and abandonment of wells. 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.

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. 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 results of operations.

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

Crude Oil, Natural Gas, and NGLs Sales Revenue Recognition

Crude oil, natural gas, and NGLs sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. This Partnership records sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. 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.

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.

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

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 footnote titled 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 2006 Limited Partnership

Index to Financial Statements





Report of Independent Registered Public Accounting Firm		27

Balance Sheets - December 31, 2016 and 2015		29

Statements of Operations - For the Years Ended December 31, 2016 and 2015		30

Statements of Partners' Equity - For the Years Ended December 31, 2016 and 2015		31

Statements of Cash Flows - For the Years Ended December 31, 2016 and 2015		32

Notes to Financial Statements		33

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited		43

Report of Independent Registered Public Accounting Firm

To the Partners of the Rockies Region 2006 Limited Partnership:

We have audited the accompanying balance sheet of Rockies Region 2006 Limited Partnership (Partnership) as of December 31, 2016 and the related statements of operations, partners’ equity and cash flows for the year then ended. The Partnership’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit 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. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal controls over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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 audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2016, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 2 to the financial statements, the Partnership has suffered recurring losses from operations, which raises substantial doubt about its ability to continue as a going concern. Management's plans regarding those matters are described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 9 to the financial statements, the Partnership has had significant related party transactions with its Managing General Partner, PDC Energy, Inc., and its subsidiaries.

/s/ Schneider Downs & Co., Inc.

Pittsburgh, Pennsylvania

March 28, 2017

Report of Independent Registered Public Accounting Firm

To the Partners of the Rockies Region 2006 Limited Partnership:

In our opinion, the accompanying balance sheets and the related statements of operations, partners’ equity, and cash flows present fairly, in all material respects, the financial position of Rockies Region 2006 Limited Partnership at December 31, 2015, and the results of its operations and its cash flows of 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.

The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 2 to the financial statements, the negative impact to the Partnership’s liquidity resulting from declining commodity prices raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 9 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 2006 Limited Partnership

Balance Sheets



	December 31, 2016			December 31, 2015
Assets
Current assets:
Cash and cash equivalents	$	11,215		$	12,445
Accounts receivable	58,187			53,932
Crude oil inventory	59,362			57,846
Total current assets	128,764			124,223

Crude oil and natural gas properties, successful efforts method, at cost	1,895,810			1,521,446
Less: Accumulated depreciation, depletion and amortization	(779,728		)	(571,528		)
Crude oil and natural gas properties, net	1,116,082			949,918
Total Assets	$	1,244,846		$	1,074,141

Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	5,588		$	4,326
Due to Managing General Partner-other, net	322,249			135,480
Current portion of asset retirement obligations	977,500			345,000
Total current liabilities	1,305,337			484,806

Asset retirement obligations	1,551,929			1,846,433
Total liabilities	2,857,266			2,331,239

Commitments and contingent liabilities

Partners' Equity:
Managing General Partner	(5,532,608		)	(5,401,139		)
Limited Partners - 4,497.03 units issued and outstanding	3,920,188			4,144,041
Total Partners' Equity	(1,612,420		)	(1,257,098		)
Total Liabilities and Partners' Equity	$	1,244,846		$	1,074,141

See accompanying notes to financial statements.

Rockies Region 2006 Limited Partnership

Statements of Operations



	Year Ended December 31,
	2016			2015
Revenues:
Crude oil, natural gas and NGLs sales	$	825,271		$	779,509

Operating costs and expenses:
Crude oil, natural gas, and NGLs production costs	628,457			658,989
Direct costs - general and administrative	177,663			163,009
Depreciation, depletion and amortization	208,200			379,645
Accretion of asset retirement obligations	166,273			126,736
Impairment of crude oil and natural gas properties	—			4,611,188
Total operating costs and expenses	1,180,593			5,939,567

Net loss	$	(355,322	)	$	(5,160,058	)

Net loss	$	(355,322	)	$	(5,160,058	)
Less: Managing General Partner interest in net loss	(131,469		)	(1,909,221		)
Net loss allocated to Investor Partners	$	(223,853	)	$	(3,250,837	)

Investor Partner units outstanding	4,497			4,497

Net loss per Investor Partner unit	$	(49.78	)	$	(722.89	)

See accompanying notes to financial statements.

Rockies Region 2006 Limited Partnership

Statements of Partners' Equity

For the Years Ended December 31, 2016 and 2015



				Managing
	Investor			General
	Partners			Partner			Total

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

Distributions to partners	(29,715		)	(17,452		)	(47,167		)

Net loss	(3,250,837		)	(1,909,221		)	(5,160,058		)

Balance, December 31, 2015	4,144,041			(5,401,139		)	(1,257,098		)

Distributions to partners	—			—			—

Net loss	(223,853		)	(131,469		)	(355,322		)

Balance, December 31, 2016	$	3,920,188		$	(5,532,608	)	$	(1,612,420	)

See accompanying notes to financial statements.

Rockies Region 2006 Limited Partnership

Statements of Cash Flows



	Year Ended December 31,
	2016			2015
Cash flows from operating activities:
Net loss	$	(355,322	)	$	(5,160,058	)
Adjustments to net loss to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	208,200			379,645
Accretion of asset retirement obligations	166,273			126,736
Impairment of crude oil and natural gas properties	—			4,611,188
Changes in assets and liabilities:
Accounts receivable	(4,255		)	5,538
Crude oil inventory	(1,516		)	(4,053		)
Accounts payable and accrued expenses	1,262			(1,952		)
Asset retirement obligations	(147,713		)	—
Due to Managing General Partner-other, net	140,512			36,594
Net cash from operating activities	7,441			(6,362		)
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	(8,671		)	(70,252		)
Net cash from investing activities	(8,671		)	(70,252		)
Cash flows from financing activities:
Distributions to Partners	—			(47,167		)
Net cash from financing activities	—			(47,167		)

Net change in cash and cash equivalents	(1,230		)	(123,781		)
Cash and cash equivalents, beginning of period	12,445			136,226
Cash and cash equivalents, end of period	$	11,215		$	12,445

Supplemental disclosure of non-cash activity:
Change in due to managing general partner-other, net related to purchases of properties and equipment	$	46,257		$	—
Change in asset retirement obligation, with corresponding change in crude oil and natural gas properties, net of disposal	$	319,436		$	390,715

See accompanying notes to financial statements.

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

NOTE 1 - GENERAL

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

As of December 31, 2016, there were 1,975 Investor Partners in this Partnership. PDC is the designated Managing General Partner of this Partnership and owns a 37 percent 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 percent to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership, and 37 percent 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. Since the formula for the repurchase price is set at a minimum of four times the most recent 12 months of cash distribution, due to the suspension of cash distributions in the first quarter of 2017, there is no value upon which to base the calculation. Through December 31, 2016, the Managing General Partner had repurchased 163.8 units of Partnership interests from the Investor Partners at an average price of $2,351 per unit. As of December 31, 2016, the Managing General Partner owned 39.3 percent 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 - GOING CONCERN

This Partnership has historically funded its operations with cash flows from operations. This Partnership’s most significant cash outlays have related to its operating expenses, capital program and distributions to partners. The market price for crude oil, natural gas, and NGLs decreased significantly during the fourth quarter of 2015, with continued weakness through the first half of 2016. Although this Partnership experienced an increase in sales in 2016 of $46,000, or 6%, to $825,000 in 2016 compared to $780,000 in 2015 related to an increase in production due to reduced line pressures, the negative impact to its liquidity resulting from declining commodity prices raises substantial doubt about this Partnership’s ability to continue as a going concern. While this Partnership generated modest positive cash flows from operations during 2016, due to anticipated future capital expenditures required to remain in compliance with certain regulatory requirements and to satisfy asset retirement obligations, the Managing General Partner believes that cash flows from operations will be insufficient to meet this Partnership’s obligations. To the extent that the costs of plugging and abandonment activities exceed available cash flows generated by this Partnership's operations, the Managing General Partner expects to fund such activities. The Managing General Partner would recover amounts funded from future cash flows of this Partnership, if available.

One of this Partnership's most significant obligations is to the Managing General Partner, which is currently due, for reimbursement of costs paid on behalf of this Partnership by the Managing General Partner. Such amounts are generally paid to third parties for general and administrative expenses and equipment and operating costs, as well as monthly operating fees payable to the Managing General Partner. Beginning in the second quarter of 2015, this Partnership made no quarterly cash distributions to the Managing General Partner or Investor Partners, and the distributions will be suspended beginning in the first quarter of 2017 until such time that cash flows can support the necessary costs of plugging and abandoning the wells that are becoming unproductive or require capital investments that are unsupportable at current commodity prices.

The ability of this Partnership to continue as a going concern is dependent upon its ability to attain a satisfactory level of cash flows from operations. Greater cash flow would most likely occur from improved commodity pricing and, to a lesser extent, a sustained increase in production. However, historically, as a result of the normal production decline in a well's production life cycle, this Partnership has not experienced a sustained increase in production without capital expenditures.

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

The accompanying financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. The financial statements do not reflect any adjustments that might result if this Partnership is unable to continue as a going concern.

NOTE 3 - 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 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.

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. 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.

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

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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 results of operations.

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, a Level 3 fair value input, 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 obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations.

Revenue Recognition. 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

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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 for crude oil delivered through the White Cliffs pipeline as the purchasers do not provide transportation, gathering or processing. Under this method, this Partnership recognizes revenues based on the gross selling price.

Recently Adopted Accounting Standard

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 requires management to assess an entity's ability to continue as a going concern at the end of every reporting period and to provide related footnote disclosures in certain circumstances. The new standard was effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. This Partnership adopted this standard in the fourth quarter of 2016.

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.

NOTE 4 - FAIR VALUE 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.

NOTE 5 - CONCENTRATION OF RISK

Accounts Receivable. This Partnership's accounts receivable are from purchasers of crude oil, natural gas, and NGLs production. This Partnership sells substantially all of its crude oil, natural gas, and NGLs to customers who purchase crude oil, natural gas, and NGLs from 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, 2016 and 2015, this Partnership did not record an allowance for doubtful accounts and did not incur any losses on accounts receivable. As of December 31, 2016 and 2015, this Partnership had two and three customers representing 10 percent or more of the accounts receivable balances.

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

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued



	Year ended December 31,
Major Customer	2016	2015
Suncor Energy Marketing, Inc.	67%	58%
DCP Midstream, LP	23%	20%
Concord Energy, LLC	—%	22%

NOTE 6 - ASSET RETIREMENT OBLIGATIONS

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



	Year Ended December 31,
	2016			2015

Balance at beginning of period	$	2,191,433		$	1,673,982
Revisions in estimated cash flows	319,436			390,715
Obligations discharged with asset retirements	(147,713		)	—
Accretion expense	166,273			126,736
Balance at end of period	2,529,429			2,191,433
Less current portion	(977,500		)	(345,000		)
Long-term portion	$	1,551,929		$	1,846,433

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 2016, the credit-adjusted risk-free rates used to discount this Partnership's plugging and abandonment liabilities ranged from 6.5 percent to 8.2 percent. 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 2016 were due to a decrease in the estimated useful life of the wells, which resulted in an increase to the asset retirement obligation liability and a corresponding increase to crude oil and natural gas properties. 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 15 to 20 wells that are expected to be plugged and abandoned within the next 12 months.

NOTE 7 - COMMITMENTS AND CONTINGENCIES

Litigation and Legal Items. 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 recorded when environmental remediation efforts are probable and the costs can be reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews. The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2016 which have not been provided for or would otherwise have a material impact on this

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

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 an Information Request from the EPA. The Information Request sought, among other things, information related to the design, operation, and maintenance of the Managing General Partner's Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focused on historical operation and design information for 46 of the Managing General Partner's production facilities, of which one relates to this Partnership, and asks that it conduct sampling and analyses at the identified 46 facilities. These 46 facilities include four of this Partnership's wells. The Managing General Partner responded to the Information Request in January 2016. Throughout 2016, it continued to meet with the EPA, U.S. Department of Justice, and Colorado Department of Public Health and Environment, and in December 2016 it received a draft consent decree from the EPA.

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 Wattenberg Field production facilities consistent with applicable standards under Colorado law. These 65 facilities include four of this Partnership's wells. These four partnership wells are the same wells identified in the EPA Information Request noted in the previous paragraph. The ultimate outcome related to this action has not been determined at this time. This matter has been combined with the matter discussed above. The ultimate outcome related to these combined actions has not been determined at this time.

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 8 - PARTNERS' EQUITY AND CASH DISTRIBUTIONS

Partners' Equity

Limited Partner Units. A limited partner unit represents the individual interest of an individual investor partner in this Partnership. No public market exists or will develop for the units. While units of this Partnership are transferable, assignability of the units is limited, requiring the consent of the Managing General Partner. Further, individual investor partners may request that the Managing General Partner repurchase units pursuant to the unit repurchase program 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	%
Sale of productive properties	63	%	37	%
Sale of equipment	63	%	37	%
Interest income	63	%	37	%

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


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


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

Unit Repurchase Provisions. Investor Partners may request that the Managing General Partner repurchase limited partnership units at any time beginning with the third anniversary of the first cash distribution of this Partnership. The repurchase price is set at a minimum of four times the most recent 12 months of cash distributions from production. Since this partnership has not made any cash distributions to the Investor Partners in over 12 months, the unit repurchase program is unable to purchase units from Investor Partners. In accordance with the Partnership Agreement, the Managing General Partner has elected to suspend cash distributions, beginning in the first quarter of 2017, in order to fund the plugging and abandonment costs of certain Partnership wells. Since the formula for the repurchase price is set at a minimum of four times the most recent 12 months of cash distributions, due to this Partnership making no cash distributions over the most recent 12 months, the Managing General Partner is unable to repurchase units as there is no value upon which to base the calculation. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10 percent 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.

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued

The Managing General Partners did not have any limited partner unit repurchases during the three months ended December 31, 2016.

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. Additionally, as the wells have gotten older and the likelihood of plugging and abandonment activities are more likely to occur in the foreseeable future, the Managing General Partner has elected to suspend distributions, beginning in the first quarter of 2017, to cover the costs of necessary plugging and abandonment activities. As a result of the impact to the cash distribution policy, if cash were to become available in excess of the plugging and abandonment activities, the Managing General Partner would likely hold cash distributions until the current asset retirement obligations are significantly reduced. Based on current economic conditions, it appears likely that the costs of plugging and abandonment operations will exceed available cash and earnings from this Partnership. The Managing General Partner makes cash distributions of 63 percent to the Investor Partners and 37 percent to the Managing General Partner. Cash distributions began in May 2007. This Partnership has made no quarterly cash distributions to the Managing General Partner or Investor Partners since the first quarter of 2015. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:



	Year Ended December 31,
	2016		2015

Cash distributions	$	—	$	47,167

NOTE 9 - TRANSACTIONS WITH MANAGING GENERAL PARTNER

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

The 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,
	2016			2015
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	76,028		$	59,824
Other ⁽¹⁾	(398,277		)	(195,304		)
Total Due to Managing General Partner-other, net	$	(322,249	)	$	(135,480	)


(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. Included in the amount as of December 31, 2016 is $46,257 due to the Managing General Partner for purchases of well equipment.

The following table presents Partnership transactions with the Managing General Partner for the years ended December 31, 2016 and 2015. “Well operations and maintenance” are included in the “Crude oil, natural gas, and NGLs production costs” line item on the statements of operations.

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS - Continued



	Year Ended December 31,
	2016		2015
Well operations and maintenance (1)	$	592,903	$	633,271
Direct costs - general and administrative (2)	177,663		163,009
Cash distributions (3)	—		18,219


(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.

ROCKIES REGION 2006 LIMITED PARTNERSHIP

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 year ended December 31, 2015 include $767 related to equity cash distributions for Investor Partner units that have been repurchased by PDC.

NOTE 10 - IMPAIRMENT OF CRUDE OIL AND NATURAL GAS PROPERTIES

In 2015, this Partnership recognized an impairment charge of approximately $4.6 million to write-down 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 $479,000, excluding estimated salvage value of $471,000, 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. This Partnership did not record an impairment charge in 2016.

ROCKIES REGION 2006 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 2016 and 2015 crude oil, natural gas, and NGLs reserves. As of December 31, 2016 and 2015, 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, 2016 and 2015, there are no proved undeveloped reserves for this Partnership.

The following table presents the indicated index price for our reserves, as required by SEC regulations and are referred to as SEC commodity prices:



	Average Benchmark Prices
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2016	$	42.75	$	2.48	$	42.75
2015	50.28		2.58		50.28

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



	Price Used to Estimate Reserves
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2016	$	38.70	$	1.95	$	10.79
2015	42.07		2.07		10.60

ROCKIES REGION 2006 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:



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

Proved reserves, January 1, 2015	158		1,192		140		497
Revisions of previous estimates and reclassifications	(102	)	(1,015	)	(115	)	(386	)
Production	(16	)	(44	)	(6	)	(29	)
Proved reserves, December 31, 2015	40		133		19		82

Revisions of previous estimates and reclassifications	21		133		18		61
Production	(16	)	(56	)	(8	)	(33	)
Proved reserves, December 31, 2016	45		210		29		110


Proved Developed Reserves, as of:

December 31, 2015	40		133		19		82
December 31, 2016	45		210		29		110

2016 Activity. As of December 31, 2016, this Partnership recorded an upward revision of its previous estimate of proved reserves by approximately 61 MBoe. The revision includes upward revisions to previous estimates of 21 MBbl of crude oil, 133 MMcf of natural gas, and 18 MBbl of NGLs. The upward revisions were the result of reductions in gathering system line pressures, which has enhanced the productive profile of some of this Partnership's wells. There were no proved undeveloped reserves developed in 2016 and no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2016.

2015 Activity. As of December 31, 2015, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 386 MBoe. The revision includes downward revisions to previous estimates of 102 MBbl of crude oil, 1,015 MMcf of natural gas, and 115 MBbl of NGLs. The downward revisions were the result of reduced asset performance. 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.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves

The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each year were adjusted for Btu content and transportation. Production, development and abandonment costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, or to depreciation, depletion, and amortization expense. No income taxes were considered in the standardized measure as this Partnership is not subject to income tax.

The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited

estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves.



	As of December 31,
	2016			2015
Future estimated cash flows	$	2,490,900		$	2,174,400
Future estimated production costs	(1,707,000		)	(1,386,800		)
Future estimated abandonment costs	(3,043,100		)	(949,300		)
Future net cash flows	(2,259,200		)	(161,700		)
10% annual discount for estimated timing of cash flows	704,100			119,300
Standardized measure of discounted future estimated net cash flows	$	(1,555,100	)	$	(42,400	)

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 September 2006. This Partnership currently owns an undivided working interest in 59 gross (58.9 net) productive crude oil and natural gas wells located in the Wattenberg Field within the Denver-Julesburg Basin, northeast of Denver, Colorado.

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



	As of December 31,
	2016			2015
Leasehold costs	$	126,373		$	8,004
Development costs (1)	1,769,437			1,513,442
Crude oil and natural gas properties, successful efforts method, at cost	1,895,810			1,521,446
Less: Accumulated DD&A	(779,728		)	(571,528		)
Crude oil and natural gas properties, net	$	1,116,082		$	949,918


⁽¹⁾	Includes estimated costs associated with this Partnership's asset retirement obligations.

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.

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

FINANCIAL DISCLOSURE

Information relating to this Item was included in a Form 8-K filed on June 15, 2016 pursuant to Regulation 14 and is incorporated by reference in this report.

There were no (i) “disagreements” (as that term is described in Item 304(a)(1)(iv) of Regulation S-K) with the predecessor certifying accountant on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which, if not resolved to the predecessor certifying accountant’s satisfaction, would have caused it to make reference to the subject matter thereof in its reports covering applicable prior fiscal years.

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, 2016, 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, 2016.

(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, 2016, 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, 2016.

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, 2016, 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 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.

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, 2016, 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.	54	President, Chief Executive Officer and Director	2015	2019

David W. Honeyfield	50	Senior Vice President and Chief Financial Officer	—	—

Lance A. Lauck	54	Executive Vice President Corporate Development and Strategy	—	—

Scott J. Reasoner	56	Chief Operating Officer	—	—

Daniel W. Amidon	56	Senior Vice President, General Counsel and Secretary	—	—

Jeffrey C. Swoveland	62	Non-Executive Chairman	1991	2017

Joseph E. Casabona	73	Director	2007	2017

Anthony J. Crisafio	64	Director	2006	2018

Larry F. Mazza	56	Director	2007	2019

David C. Parke	50	Director	2003	2017

Kimberly Luff Wakim	59	Director	2003	2018

Randy S. Nickerson	55	Director	2017	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.

David W. Honeyfield, PDC's Chief Financial Officer and Senior Vice President joined PDC in December 2016. Mr. Honeyfield has over 25 years of energy and natural resource related experience, including a background in accounting, finance, midstream and marketing, operations, treasury, and capital markets. Mr. Honeyfield was most recently Vice President and Chief Financial Officer for Jonah Energy LLC based in Denver, Colorado. His previous experience includes six years at Intrepid Potash, Inc. most recently as President and Chief Financial Officer. Previously, he served in various leadership roles at SM Energy Company, Cimarex Energy Co., and Arthur Andersen LLP. Mr. Honeyfield currently serves on the Board of Directors for Children's Hospital Colorado where he chairs the Finance Committee, he serves on the Board of the Winter Park Ski Education Foundation, and was former President of the Board for Habitat for Humanity of Metro Denver. Mr. Honeyfield holds a Bachelors of Arts in Economics from the University of Colorado and is a Certified Public Accountant ("CPA").

Lance A. Lauck was appointed as PDC's Executive Vice President Corporate Development and Strategy in January 2015. Mr. Lauck has overall responsibilities for PDC's business development, acquisitions and divestitures, 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 Chief Operating Officer, a position to which he was appointed in January 2017. 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 is PDC's 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. Honeyfield and 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. Honeyfield became a Named Executive Officer effective December 19, 2016 and 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 served as a member of the Board of Directors of Linn Energy, LLC (NASDAQ: LINE), a public independent oil and natural gas company from 2006 to 2017.

Joseph E. Casabona, a CPA, was first elected to the Board in 2007. Mr. Casabona is presently the CEO of Halio Energy Inc. (HOIL), which is traded on the Canadian TSX.V and headquartered in Vancouver, Canada. He previously 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.

Anthony J. Crisafio, a CPA and A National Association of Corporate Directors (NACD) Board Leadership Fellow, 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 for a number of companies in the past five years including Empire Energy, LLC, MDS Associated Companies, TruFoodMfg, and others. 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 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, Chief Executive Officer and Director of MVB Financial Corp ("MVB"), a multi-state financial services company. He has more than 28 years of experience in both large banks and 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. He also serves on the board of directors of a private financial technology startup, Billgo, headquartered in Fort Collins, Colorado. 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.

David C. Parke, who was first elected to the Board in 2003, has served as a Managing Director of EVOLUTION Life Science Partners since October 2014. From June 2011 until October 2014, he was a Managing Director in the investment banking group of Burrill Securities LLC, an investment banking firm. 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.

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 a member 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.

Randy S. Nickerson, was elected to the Board on March 4, 2017. Mr. Nickerson currently serves as the Executive Vice President, Corporate Strategy of Marathon Petroleum Corporation (“MPC”) and Executive Vice President and Chief Commercial Officer, MarkWest assets, of the general partner of MPLX LP (“MPLX”). Mr. Nickerson has announced his retirement from these positions, effective April 1, 2017, at which point he intends to continue to serve MPC and MPLX in a consulting and advisory capacity. Mr. Nickerson joined MPC in 2015, at the time of MPC and MarkWest combination. From 1995 to 2015, Mr. Nickerson worked for MarkWest Energy Partners and its predecessors and affiliated entities (“MarkWest”) in a series of operational and technical positions of increasing responsibility, culminating with the role of Senior Vice President, Corporate Development and Chief Commercial Officer. Prior to his time with MarkWest, Mr. Nickerson served as Senior Project Manager and Regional Engineering Manager for Western Gas Resources, Inc., from 1990 to 1995, and for Chevron USA and Meridian Oil Inc. in various process and project engineering positions from 1984 to 1990. Mr. Nickerson earned a bachelor’s degree in chemical engineering from the Colorado State University.

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 2016 or 2015 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, 2016, concerning the Managing General Partner's interest in this Partnership and other persons known by this Partnership to own beneficially more than 5% of the interests in this Partnership. Each partner exercises sole voting and investing power with respect to the interest beneficially owned.



	Limited Partnership Units
	Number of	Number of Units Beneficially Owned	Percentage of Total Units Outstanding		Percentage of
	Units				Total Partnership
	Outstanding Which				Interests
	Represent 63% of Total				Beneficially
Person or Group	Partnership Interests (1)				Owned
	4,497.03
PDC Energy, Inc. (2) (3) (4) (5)	—	163.8	3.64	%	2.29	%


(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 percent 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. [(163.8 units/4,497.03 units)*63 percent limited partnership ownership]


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

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.

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.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

This Partnership dismissed PricewaterhouseCoopers LLP ("PwC") on June 9, 2016, as the principal accountant and the Audit Committee of the Managing General Partner approved the appointment of Schneider Downs & Co., Inc. ("Schneider Downs") as the principal accountant for the fiscal year ending December 31, 2016, effective June 9, 2016. The following table presents amounts charged by this Partnership's independent registered public accounting firms, Schneider Downs and PwC, for the years shown:



	Year Ended December 31,
Type of Service	2016		2015
PwC Audit Fees (1)	$	20,000	$	136,000
PwC Audit-Related Fees (2)	15,000		—
Schneider Downs Audit Fees (1)	91,000		—
Total Fees	$	126,000	$	136,000


(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.


(2)	Audit-related fees consist of fees related to transition of this Partnership's principal accountant from PwC to Schneider Downs in 2016.

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 27.

(b) Exhibits index.

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

3.1

Limited Partnership Agreement

10-12G/A Amend 1

000-52787

12/24/2007

3.2

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

10-12G/A Amend 1

000-52787

3.1

12/24/2007

10.1

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

10-12G/A Amend 1

000-52787

10.2

12/24/2007

10.2

Form of assignment of leases to this Partnership

10-12G/A Amend 1

000-52787

10.1

12/24/2007

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, 2016 of PDC Energy, Inc. and its subsidiaries, as Managing General Partner of this Partnership.

10-K

001-37419

02/28/2017

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.

ITEM 16. FORM 10-K SUMMARY

None.

SIGNATURES

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

Rockies Region 2006 Limited Partnership

By its Managing General Partner

PDC Energy, Inc.



	By: /s/ Barton R. Brookman, Jr.
	Barton R. Brookman, Jr. President, Chief Executive Officer and Director of PDC Energy, Inc.
	March 28, 2017

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 28, 2017
Barton R. Brookman, Jr.	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal executive officer)

/s/ David W. Honeyfield	Senior Vice President and Chief Financial Officer	March 28, 2017
David W. Honeyfield	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	March 28, 2017
R. Scott Meyers	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal accounting officer)

/s/ Jeffrey C. Swoveland	Chairman and Director	March 28, 2017
Jeffrey C. Swoveland	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Joseph E. Casabona	Director	March 28, 2017
Joseph E. Casabona	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Anthony J. Crisafio	Director	March 28, 2017
Anthony J. Crisafio	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Larry F. Mazza	Director	March 28, 2017
Larry F. Mazza	PDC Energy, Inc.
	Managing General Partner of the Registrant

/s/ Kimberly Luff Wakim	Director	March 28, 2017
Kimberly Luff Wakim	PDC Energy, Inc.
	Managing General Partner of the Registrant

Attached files

Rockies Region 2006 Limited Partnership Reports

Also read