Attached files

file filename
EX-32.1 - 906 CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - ROCKIES REGION 2007 LPrr07-ex321_20171231.htm
EX-99.1 - REPORT OF INDEPENDENT PETROLEUM CONSULTANTS - RYDER SCOTT COMPANY, L.P. - ROCKIES REGION 2007 LPrr07-ex991_20171231.htm
EX-31.2 - 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - ROCKIES REGION 2007 LPrr07-ex312_20171231.htm
EX-31.1 - 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - ROCKIES REGION 2007 LPrr07-ex311_20171231.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, 2017
or
£  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD ____________ TO ____________
Commission File Number 000-53201
Rockies Region 2007 Limited Partnership

(Exact name of registrant as specified in its charter)
 
West Virginia
 
26-0208835
 
 
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
1775 Sherman Street, Suite 3000, Denver, Colorado  80203
(Address of principal executive offices)     (Zip code)
Registrant's telephone number, including area code  (303) 860-5800
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
 
Title of Each Class
 
 
Limited Partnership Interests
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £  No R
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £  No R
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes R  No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R  No £
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth 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)
Emerging growth company £
 
 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act£

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, 2018, this Partnership had 4,470 units of limited partnership interest and no units of additional general partnership interest outstanding.



Rockies Region 2007 Limited Partnership
2017 Annual Report on Form 10-K
Table of Contents
 
 
Page
 
Part I
 
Item 1
Business
Item 1A
Risk Factors
Item 1B
Unresolved Staff Comments
Item 2
Properties
Item 3
Legal Proceedings
Item 4
Mine Safety Disclosures
 
 
 
 
Part II
 
Item 5
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6
Selected Financial Data
Item 7
Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A
Quantitative and Qualitative Disclosures About Market Risk
Item 8
Financial Statements and Supplementary Data
Item 9
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A
Controls and Procedures
Item 9B
Other Information
 
 
 
 
Part III
 
Item 10
Directors, Executive Officers and Corporate Governance
Item 11
Executive Compensation
Item 12
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13
Certain Relationships and Related Transactions and Director Independence
Item 14
Principal Accountant Fees and Services
 
 
 
 
Part IV
 
Item 15
Exhibits, Financial Statement Schedules
Item 16
Form 10-K Summary
 
 
 
Signatures
 
 
 



PART I

WHERE YOU CAN FIND ADDITIONAL INFORMATION

The Rockies Region 2007 Limited Partnership (this “Partnership” or the “Registrant”) is subject to the reporting and information requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and is as a result obligated to file periodic reports, proxy statements and other information with the United States ("U.S.") Securities and Exchange Commission ("SEC"). The SEC maintains a website that contains the annual, quarterly and current reports, proxy and information statements, and other information regarding this Partnership, which this Partnership electronically files with the SEC. The address of that site is http://www.sec.gov. The Central Index Key for this Partnership is 0001407805. You can read and copy any materials this Partnership files with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 on official business days during the hours of 10 a.m. to 3 p.m. You may obtain information on the operation of the Public Reference Room by calling the SEC at (800) SEC-0330.

UNITS OF MEASUREMENT

Definitions used throughout the document:

Bbl - One barrel of crude oil or natural gas liquids ("NGLs") or 42 gallons of liquid volume.
Boe - One barrel of crude oil equivalent, with each barrel comprised of one barrel of crude oil or NGLs or 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.


1




SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 regarding this Partnership's business, financial condition, and results of operations. PDC Energy, Inc. (“PDC”) is the Managing General Partner of this Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. Words such as expect, anticipate, intend, plan, believe, seek, estimate, and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements may relate to, among other things: future production (including the components of such production), sales, expenses, cash flows, and liquidity; estimated crude oil, natural gas, and natural gas liquids ("NGLs") reserves; anticipated capital expenditures and projects; availability of additional midstream facilities and services, timing of that availability and related benefits to this Partnership; the impact of high gathering system line pressures; the effect of environmental or regulatory actions; 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 and prices for the products this Partnership produces;
volatility of commodity prices for crude oil, natural gas, and NGLs;
impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement of those laws and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations;
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;
increases or changes in operating costs, severance and ad valorem taxes;
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, including recent environmental litigation;
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.


2




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 a working interest in wells located in Colorado from which this Partnership produces and sells crude oil, natural gas, and NGLs. This Partnership was organized and began operations in 2007 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”) and the Managing General Partner. The Investor Partners own 63 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 partner 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, 2057, unless dissolved in certain circumstances stipulated in the Agreement, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

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

Business Strategy

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

Going Concern

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


3




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 and abandoning wells which are not expected to be economic to restore to production, or that have been deemed not capable of production, in order to minimize future additional costs. For wells that are not currently producing, but are expected to be economic to restore, workovers may be performed in an attempt 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 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 expected to be used 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 aged and the likelihood of plugging and abandonment activities 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. 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

This Partnership operates vertical wells exclusively in the Wattenberg Field, located in the Denver-Julesburg Basin northeast of Denver, Colorado. This Partnership had 53 and 73 productive wells in this field as of December 31, 2017 and 2016, respectively, as 20 wells were plugged and abandoned during the year ended December 31, 2017. The wells 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 toward 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 53 vertical wells were all drilled in the Codell formation, with some also completed in other formations. 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 from the wells, issues from hydraulic fracturing of nearby horizontal wells, or well bore mechanical testing. As of December 31, 2017, 17 of this Partnership's 53 wells are shut-in.

4





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 pressure of the gathering system, the wells will continue to produce, although the value of 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. The relatively lower commodity prices in recent years have resulted in reduced investment in midstream facilities by this Partnership's third-party midstream service provider, 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 the third quarter of 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. This Partnership's average gathering system line pressures were 35 percent higher in 2017 as compared to 2016. The 2017 production from this Partnership decreased to 45,887 Boe compared to 71,557 Boe produced in 2016, reflecting the operational result of increasingly high gathering system line pressures 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.

Crude Oil and Natural Gas Properties

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 in which it has a well bore working interest as of December 31, 2017 and 2016:
 
 
Productive Natural Gas Wells
 
 
2017
 
2016
Location
 
Gross
 
Net
 
Gross
 
Net
 
 
 
 
 
 
 
 
 
    Wattenberg Field
 
53.0

 
51.9

 
73.0
 
71.9

As of December 31, 2017, 17 of this Partnership's 53 productive wells were shut-in for various reasons, including production equipment failures, environmental protection requirements, well bore integrity testing for nearby horizontal wells, and the need to build up well head pressure to overcome high line pressures. This Partnership plugged and abandoned 20 wells in 2017 and expects to plug and abandon an additional 15 wells during 2018, as the operating and future required capital are expected to produce uneconomic results for these wells.

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, 2017, 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.


5




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 and accounting 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 or 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.


6




The SEC's reserve rules allow the use of techniques that have been proved effective by evaluation of actual production from projects in the same reservoir or an analogous reservoir or by other observational 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 2017 reserve estimates. Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. The New York Mercantile Exchange ("NYMEX") prices used in preparing the reserves are then adjusted based on 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,
 
 
2017
 
2016
Crude oil (SEC NYMEX - $/Bbl)
 
$
51.34

 
$
42.75

Natural gas (SEC NYMEX - $/MMBtu)
 
2.98

 
2.48


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 geologic and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows is intended to represent the current market value of this Partnership's proved reserves. See Item 8, Financial Statements and Supplemental Data - Net Proved Reserves, for additional information regarding this Partnership's reserves. As of December 31, 2017 and 2016, 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,
 
 
2017
 
2016
Proved Reserves
 
 
 
 
Natural Gas (MMcf)
 
416

 
545

Crude Oil and Condensate (MBbl)
 
75

 
107

NGLs (MBbl)
 
54

 
68

Total proved reserves (MBoe)
 
198

 
266


The decrease in proved reserves as of December 31, 2017 compared to December 31, 2016 was mainly due to volumes produced in 2017. The future estimated undiscounted operating cash flows were a negative $137,000 and $1,641,000 at December 31, 2017 and 2016, respectively. 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. The estimated undiscounted operating cash flows as of December 31, 2017 increased as compared to December 31, 2016 as a result of the aforementioned increase in NYMEX pricing.

Production, Sales, Prices, and Production Costs

For information regarding this Partnership's net production volumes, crude oil, natural gas, and NGLs sales, average selling price received, and average production cost, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, included elsewhere in this report.


7




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 Midstream, LP ("DCP"), and ARM Energy Management. Sales to these parties represented 38 percent, 33 percent and 21 percent, respectively, of this Partnership's 2017 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 sells its natural gas to DCP, a third-party 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. 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. This Partnership's NGLs are sold at the tailgate of the midstream service provider's processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed.

Provision for Underpayment of Natural Gas Sales. During the second quarter of 2016, an overriding royalty owner notified the Managing General Partner that the owner believed certain charges and costs had been improperly deducted before applying the owner’s overriding royalty percentage in certain of this Partnership’s wells in which this owner has an interest. The Managing General Partner and the owner agreed on a settlement amount and in June 2016, this Partnership recorded a charge to crude oil, natural gas and NGLs sales of approximately $63,000 for this settlement. The settlement was paid to the overriding royalty owner and deducted from this Partnership's cash distributions in the third quarter of 2016.

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.


8




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. Rates and charges for the transportation of natural gas in interstate commerce, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Natural gas pipeline companies hold certificates of public convenience and necessity issued by FERC authorizing ownership and operation of certain pipelines, facilities and properties. 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. 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.

Transportation and safety of natural gas is also subject to regulation by the United States Department of Transportation under the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2012.
The availability, terms, and cost of transportation affect this Partnership's natural gas sales. 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. Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are subject to state regulation, however, which includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements.
The Colorado Oil and Gas Conservation Commission has adopted or amended numerous rules in recent years, including rules relating to safety matters and flowline safety, integrity management and leak prevention and detection.  

Environmental Matters

Due to the nature of the oil and natural 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. Except as discussed herein, the Managing General Partner is not aware of any material environmental claims existing as of December 31, 2017 which have not been provided for or would otherwise have a material impact on this Partnership's financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other potential sources of liability will not be discovered on this Partnership's properties. However, the liability ultimately incurred with respect to a matter may exceed the related accrual.


9




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. PDC has a fiduciary duty to utilize its best efforts, exercise good faith, and deal fairly with Investor Partners to carry out the business of this Partnership. PDC's executive staff manages the affairs of this Partnership, while technical geosciences and petroleum engineering staff oversee the operations aspects 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; 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.

10





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, 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 its 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.


11





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. See the footnote titled Commitments and Contingencies to this Partnership's financial statements included elsewhere in this report.


ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

12





PART II


ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES

As of December 31, 2017, this Partnership had 1,756 Investor Partners holding 4,470 units and one Managing General Partner. The investments held by the Investor Partners are in the form of limited partnership interests. Investor Partners' interests are transferable; however, no assignee of units in this Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. Through December 31, 2017, the Managing General Partner has repurchased 153.3 units of Partnership interests from Investor Partners.

Market. There is no public market for this Partnership's units, nor will a public market develop for these units in the future. Investor Partners may not be able to sell their Partnership interests or may only be able to sell their Partnership 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. This Partnership has suspended cash distributions, with the exception of withholding Investor Partners' tax payments, until such time, if at all, that cash flows can reasonably be expected to support the necessary costs of operations and the expected plugging and abandoning of the wells that are becoming unproductive and/or the required capital investments for regulatory requirements, and this Partnership becomes current on its obligations. 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.




13




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, August 31, 2007
 
$
128,062,693

Distributions, during the year ended December 31, 2017
 
(9,654
)
Distributions, during the year ended December 31, 2016
 
(408,051
)
Distributions, from inception through December 31, 2017
 
$
(113,779,807
)

Due to the current commodity price environment, the significantly increased line pressure, ongoing operating costs, production taxes, direct costs - general and administrative, and the costs incurred and expected to be incurred for plugging and abandoning wells, the Managing General Partner believes that this Partnership will not be able to sustain positive net cash flows in the foreseeable future.

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. The formula for the repurchase price is set at a minimum of four times the most recent 12 months of cash distributions. Due to the suspension of cash distributions as of March 31, 2017, there is no value upon which to base the calculation, and therefore, no repurchase offers are currently being considered. 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 Partner did not have limited partner unit repurchases during the three months ended December 31, 2017.


ITEM 6. SELECTED FINANCIAL DATA

Not applicable.


14




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

This Partnership’s operations for the year ended December 31, 2017 were impacted by a number of noteworthy items. Aggregate crude oil, natural gas, and NGLs production decreased 36 percent for the year ended December 31, 2017 compared to the year ended December 31, 2016. Crude oil production decreased 46 percent for the year ended December 31, 2017 compared to the year ended December 31, 2016. The primary drivers for the continued decrease in production include increasingly high gathering system line pressures and the natural decline rates of this Partnership's wells. This Partnership’s midstream service provider is currently processing at full capacity and basin-wide development and production continues to increase; therefore, line pressures continue to be elevated.

This Partnership’s plugging and abandonment activities for the year ended December 31, 2017 involved 20 wells with estimated costs totaling $1,064,000 resulting in a gain of $13,000 as actual plugging costs were less than expected. These 20 wells were plugged and abandoned as they were expected to be uneconomic to operate given natural decline rates, the elevated gathering system line pressures, and anticipated capital spending levels that would be required to meet newly-implemented environmental standards. This Partnership’s plugging and abandonment activities for the year ended December 31, 2016 involved two wells with estimated costs totaling $59,000, which resulted in a gain of $8,000 as actual plugging costs were less than expected.

The Managing General Partner recently received a refund totaling $201,000 of previously-remitted state sales and use tax from Colorado related to wells this Partnership drilled and equipped in 2008. This nonrecurring settlement impacted the value of oil and gas properties and resulted in a gain on the recovery of sales tax refund and interest income.

When considering the current commodity price environment, the significantly increased line pressure, ongoing operating costs, production taxes, direct costs - general and administrative, and the costs incurred and expected to be incurred for future plugging and abandoning wells, the Managing General Partner believes that this Partnership will not be able to sustain positive net cash flows in the foreseeable future. Accordingly, this Partnership has suspended cash distributions, with the exception of distributions on behalf of Investor Partners for withholding taxes, until such time, if at all, that cash flows can reasonably be expected to support the necessary costs of operations and the expected plugging and abandoning of the wells that are becoming unproductive and/or the required capital investments for regulatory requirements, and this Partnership becomes current on its obligations. 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 potentially mitigate risks impacting 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. 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. See footnote Subsequent Event to the financial statements included elsewhere in this report.


15




Results of Operations

Summary Operating Results

The following table presents selected information regarding this Partnership’s results from continuing operations:
 
Year ended December 31,
 
2017
 
2016
 
 Change
Number of gross productive wells (end of period) (1)
53

 
73

 
(27
)%
 
 
 
 
 
 
Production
 

 
 
 
 

Crude oil (Bbl)
17,306

 
32,273

 
(46
)%
Natural gas (Mcf)
97,278

 
132,418

 
(27
)%
NGLs (Bbl)
12,368

 
17,214

 
(28
)%
Crude oil equivalent (Boe)
45,887

 
71,557

 
(36
)%
Average Boe production per day
126

 
196

 
(36
)%
 
 
 
 
 
 
Crude oil, natural gas and NGLs sales
 

 
 

 
 

Crude oil
$
838,175

 
$
1,261,184

 
(34
)%
Natural gas
213,418

 
226,744

 
(6
)%
NGLs
195,120

 
168,044

 
16
 %
Provision for underpayment of natural gas sales

 
(63,262
)
 
*

Total crude oil, natural gas and NGLs sales
$
1,246,713

 
$
1,592,710

 
(22
)%
 
 
 
 
 
 
Average selling price
 

 
 

 
 

Crude oil (per Bbl)
$
48.43

 
$
39.08

 
24
 %
Natural gas (Mcf)
2.19

 
1.71

 
28
 %
NGLs (Bbl)
15.78

 
9.76

 
62
 %
Crude oil equivalent (per Boe)
27.17

 
23.14

 
17
 %
 
 
 
 
 
 
Average cost per Boe
 
 
 
 
 
Lease operating expenses
$
13.95

 
$
12.36

 
13
 %
Production Taxes
1.03

 
0.96

 
7
 %
Transportation, gathering, and procession expenses

 
0.34

 
*

Direct costs - general and administrative
3.77

 
2.41

 
56
 %
Depreciation, depletion, and amortization
6.06

 
5.73

 
6
 %
 
 
 
 
 
 
Cash distributions
$
9,654

 
$
408,051

 
(98
)%

*Percentage change is not meaningful.
Amounts may not recalculate due to rounding.

(1) Represents the number of wells capable of producing hydrocarbons at the end of the period, regardless of whether such wells were productive during the periods shown.




16




Crude Oil, Natural Gas, and NGLs Sales

Changes in Crude Oil, Natural Gas, and NGLs Production Volumes.  For the year ended December 31, 2017 as compared to 2016, crude oil, natural gas, and NGLs production, on a per barrel of oil equivalent ("Boe") basis, decreased 36 percent, primarily resulting from increasingly high line pressures on the gas gathering facilities and the natural decline rates of this Partnership's wells.

This Partnership’s production has historically been affected by fluctuations in gathering system line pressures in the Wattenberg Field. This Partnership relies on its third-party midstream service provider to construct gathering, compression, and processing facilities to keep pace with the overall field’s production growth.

Production from older vertical wells is susceptible to being negatively impacted by increasing gathering system line pressures compared to newer wells. Production equipment on the majority of this Partnership's wells can operate up to a certain line pressure, at which point safety valves will shut-in a well. This maximum operating line pressure is typically between 275 and 300 pounds per square inch (“psi”). During 2017, the line pressures on this Partnership's wells have sharply increased from an average of approximately 158 psi in 2016 to an average of approximately 213 psi in 2017, an increase of 35 percent. This Partnership’s midstream service provider is currently processing at full capacity and field-wide activity remains high; therefore, line pressures are expected to continue to be at high levels.

In order to manage the impact of the increased line pressures, the Managing General Partner, along with other major operators in the Wattenberg Field, continue to work closely with this Partnership's third-party midstream provider in an effort to ensure adequate system capacity going forward, as evidenced by the commitment by the midstream provider to build additional gathering and processing capacity in the field. These expansions are expected to increase the midstream provider's system capacity, assist in the control of line pressures on its natural gas gathering facilities, and reduce production curtailments in the field. The in-service dates of the midstream provider's next two plants are currently scheduled to occur in the third quarter of 2018 and in the second quarter of 2019, respectively. However, the Managing General Partner expects that line pressures will remain high until the new plants are placed in service, causing this Partnership's wells to experience challenging periods of operation that negatively impact production and may result in shut-in periods. With current and expected ongoing horizontal development in the field, this increase in capacity scheduled for 2018 may not offset all of the production increases expected in the Wattenberg Field. These increases in field-wide capacity in 2018 and beyond may not provide enough relief in line pressures to have a positive effect on this Partnership's vertical wells, due to their geographic proximity to the new plants being constructed. The timing and availability of adequate infrastructure is not within the Managing General Partner’s or this Partnership’s control.

Crude Oil, Natural Gas, and NGLs Pricing. This Partnership's results of operations depend upon many factors, particularly the price of crude oil, natural gas, and NGLs, and the Managing General Partner's ability to market this Partnership's production effectively. Crude oil, natural gas, and NGLs prices are among the most volatile of all commodity prices. The price of crude oil, natural gas, and NGLs increased during the year ended December 31, 2017, as compared to 2016, primarily due to improvements in NYMEX crude oil and natural gas prices and improved price realizations.
    
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 a pipeline as the purchasers do not provide transportation, gathering or processing. Under this method, this Partnership recognizes revenues based on the gross selling price. During the year ended December 31, 2017, this Partnership did not utilize this pipeline to transport any of its crude oil, and therefore did not incur any transportation, gathering, or processing expenses.


17




Provision for Underpayment of Natural Gas Sales. During the second quarter of 2016, an overriding royalty owner notified the Managing General Partner that the owner believed certain charges and costs had been improperly deducted before applying the owner’s overriding royalty percentage in certain of this Partnership’s wells in which this owner has an interest. The Managing General Partner and the owner agreed on a settlement amount and in June 2016, this Partnership recorded a charge to crude oil, natural gas and NGLs sales of approximately $63,000 for this settlement. The settlement was paid to the overriding royalty owner and deducted from this Partnership's cash distributions in the third quarter of 2016.

Crude Oil, Natural Gas and NGLs Production Costs

Total production costs, which consist of lease operating expenses, production taxes, and transportation and gathering costs, vary with changes in total crude oil, natural gas, and NGLs sales and production volumes. Production taxes vary directly with crude oil, natural gas, and NGLs sales and effective tax rates. When oil inventory accumulates, the cost of the production is capitalized as inventory costs. Upon sale of oil inventory, the cost of production previously capitalized is relieved from inventory and recognized as lease operating expense. Production taxes are estimated by the Managing General Partner based on tax rates determined using published information and are subject to revision based on actual amounts determined during future filings by the Managing General Partner with taxing authorities. Fixed monthly well operating costs on a per unit basis increase as production decreases. 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.

Total lease operating expenses for 2017 decreased approximately $244,000 compared to 2016, primarily due to the decrease of the number of wells producing in 2017 resulting from high line pressures and the plugging and abandonment activities, and to the impact of the timing of sales of crude oil from inventory. Fewer producing wells resulted in lower well operating and maintenance fees being charged by the Managing General Partner. Production taxes decreased 31 percent due to the decrease in crude oil, natural gas and NGLs sales. There was no crude oil delivered through a pipeline during the year ended December 31, 2017. Transportation, gathering and processing costs were $24,000 during the year ended December 31, 2016.

Direct costs - general and administrative

Direct costs - general and administrative for the year ended December 31, 2017 was consistent with 2016.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization ("DD&A") expense decreased for the year ended December 31, 2017 compared to 2016 due to a 36 percent decrease in production. The DD&A expense rate per Boe increased slightly to $6.06 for the year ended December 31, 2017 as compared to $5.73 during the same period in 2016.

Asset Retirement Obligations and Accretion Expense

During the year ended December 31, 2017, this Partnership plugged and abandoned 20 wells for a total estimated cost of approximately $1,064,000, which was offset by the release of the asset retirement obligations liability of approximately $1,077,000, resulting in a gain on settlement of asset retirement obligations of approximately $13,000

The current portion of the asset retirement obligations of $750,000 relates to 15 of this Partnership's wells that the Managing General Partner expects to be plugged and abandoned during the next 12 months. These wells are expected to be uneconomic to operate given current commodity prices, the negative impact of high line pressures on productivity and decreasing production resulting from natural declines. The costs to plug and abandon wells over the next 12 months are expected to result in a significant cash outflow for this Partnership. To the extent that the costs of plugging and abandonment activities exceed current cash balances and available cash flows generated by this Partnership's operations, the Managing General Partner will fund such activities. The Managing General Partner would then recover amounts funded from future cash flows of this Partnership, if available.

Asset retirement obligation accretion expense decreased $9,000, or five percent, to $183,000 in 2017 compared to $192,000 in 2016, primarily due to a reduction in the number of this Partnership's wells.

18





Gain on recovery of sales tax refund and interest income

The Managing General Partner recently received a refund totaling $201,000 of previously-remitted state sales and use tax related to wells this Partnership drilled and equipped in 2008 and related interest due to the Partnership. Of the amount refunded, $49,000 relates to a portion of this Partnership’s wells in the Wattenberg Field and $152,000 is related to wells in the Piceance Basin. Due to the uncertainty as to the recovery of the sales tax refund during prior periods, this Partnership did not recognize the impact of the benefit of this refund to this Partnership until the third quarter of 2017. Of the amount received related to wells in the Wattenberg Field, $39,000 was related to tangible well equipment and, accordingly, was recorded against the balance of crude oil and natural gas properties and $10,000 was recorded as interest income. This Partnership sold all of its Piceance wells in 2013 to an unrelated third-party. Because this Partnership no longer owns the associated wells, the sales tax refund totaling $121,000 previously paid on the tangible well equipment was recorded in the income statement as gain on recovery of sales tax refund and $31,000 was recorded as interest income.

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

Due to the trend of decreased liquidity that this Partnership has been experiencing in recent periods, and anticipated future expenditures required to remain compliant with certain regulatory requirements and costs of necessary plugging and abandonment activities, the Managing General Partner believes that projected cash flows from operations will be insufficient to meet this Partnership’s obligations. Commodity prices during the year ended December 31, 2017 showed improvement relative to pricing experienced during 2016. This level of price improvement alone is not likely to be sufficient to alleviate concerns regarding this Partnership’s ability to meet its obligations.

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 from the producing wells. Crude oil, natural gas, and NGLs production from existing properties are generally expected to continue a decline in the rate of production over the remaining life of the wells. These declines in production will be particularly significant during times of increased gathering system line pressures, including at the present time. 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, if ever, that cash flows can reasonably be expected to support the necessary costs of expected plugging and abandoning of the wells that are becoming unproductive and/or the required capital investments for regulatory requirements, and this Partnership becomes current on its obligations.

Working Capital

As of December 31, 2017, this Partnership had a working capital deficit of $826,000, compared to a working capital deficit of $886,000 at December 31, 2016. The decrease in the working capital deficit of $60,000 was primarily due to the following changes:

a decrease in current portion of the asset retirement obligations of $457,000; and
an increase in crude oil inventory of $23,000;

Offset in part by;

a decrease in cash and cash equivalents of $218,000;
a decrease in accounts receivable of $130,000; and
an increase in amounts due to Managing General Partner-other, net, of $72,000.


19




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 a portion of this Partnership's activities, if any, through borrowings; nor is it likely that borrowings would be supportable based on the remaining asset composition of the Partnership. Partnership borrowings, should any occur, will be non-recourse to the Investor Partners. Accordingly, this Partnership, rather than the Investor Partners, will be responsible for repaying any amounts borrowed.


Cash Flows

Operating Activities

The net cash deficit from operating activities was $452,000 for the year ended December 31, 2017, compared to net cash from operating activities of $554,000 for 2016. This Partnership's cash flows from operating activities in the year ended December 31, 2017 were primarily impacted by commodity prices, production volumes, operating costs, direct costs-general and administrative expenses, plugging and abandonment costs, and the gain on the recovery of sales tax refund. The key components of the changes in this Partnership's cash flows from operating activities are described in more detail in Results of Operations above.

Investing Activities

Cash flows from investing activities consist of investments in equipment and proceeds received from the sale of crude oil and natural gas properties, and proceeds from the recovery of the sales tax refund. 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, 2017, this Partnership investment in equipment was $61,000 compared to $66,000 in 2016. During the year ended December 31, 2017, this Partnership's proceeds from the sale of equipment salvaged from wells that were plugged and abandoned in 2017 were approximately $143,000 compared to no proceeds from such sales in 2016. During the year ended December 31, 2017, this Partnership also received a sales tax refund of approximately $161,000.

Financing Activities

Cash flows from financing activities generally consist of cash distributions to investors. During the twelve months ended December 31, 2017, this Partnership made no quarterly cash distributions to the Managing General Partner or Investor Partners since the Managing General Partner suspended cash distributions to fund this Partnership's plugging and abandonment costs. The amount of $10,000 represents mandatory state income taxes withheld and paid by this Partnership on behalf of the Investor Partners.

Off-Balance Sheet Arrangements

As of December 31, 2017, 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.


20




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 has 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 concentration is a significant 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.

21





Recent Accounting Standards

See the 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.

22




ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


Rockies Region 2007 Limited Partnership
Index to Financial Statements
 
 
 
 
 
 
Report of Independent Registered Public Accounting Firm
 
 
 
 
Balance Sheets - December 31, 2017 and 2016
 
 
 
 
Statements of Operations - For the Years Ended December 31, 2017 and 2016
 
 
 
 
Statements of Partners' Equity (Deficit) - For the Years Ended December 31, 2017 and 2016
 
 
 
 
Statements of Cash Flows - For the Years Ended December 31, 2017 and 2016
 
 
 
 
Notes to Financial Statements
 
 
 
 
Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited
 
 
 
 

23





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Partners
Rockies Region 2007 Limited Partnership

Opinion on the Financial Statements
We have audited the accompanying balance sheets of Rockies Region 2007 Limited Partnership (Partnership) as of December 31, 2017 and 2016, and the related statements of operations, partners’ equity, and cash flows for each of the years in the two-year period ended December 31, 2017, and the related notes and schedules (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, 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.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. 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 noted in Note 2 to the financial statements, the Partnership has suffered recurring losses from operations and has a net capital deficiency that raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these 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.

We have served as the Partnership’s auditor since 2016.


/s/ Schneider Downs and Company, Inc.

Pittsburgh, Pennsylvania
March 29, 2018


24




Rockies Region 2007 Limited Partnership
Balance Sheets



 
December 31, 2017
 
December 31, 2016
Assets
 
 
 

Current assets:
 
 
 

Cash and cash equivalents
$
357,711

 
$
576,132

Accounts receivable
166,651

 
296,635

Crude oil inventory
37,443

 
14,453

Total current assets
561,805

 
887,220

 
 
 
 
Crude oil and natural gas properties, successful efforts method, at cost
4,413,455

 
4,355,731

Less: Accumulated depreciation, depletion and amortization
(2,578,345
)
 
(2,300,187
)
Crude oil and natural gas properties, net
1,835,110

 
2,055,544

Total Assets
$
2,396,915

 
$
2,942,764

 
 
 
 
Liabilities and Partners' Equity (Deficit)
 
 
 
Current liabilities:
 
 
 
Due to Managing General Partner-other, net
$
638,081

 
$
565,842

Current portion of asset retirement obligations
750,000

 
1,207,500

Total current liabilities
1,388,081

 
1,773,342

 
 
 
 
Asset retirement obligations
1,450,305

 
1,701,009

Total liabilities
2,838,386

 
3,474,351

 
 
 
 
Commitments and contingent liabilities

 

 
 
 
 
Partners' Equity (Deficit):
 
 
 
   Managing General Partner
(5,353,720
)
 
(5,390,635
)
   Limited Partners - 4,470 units issued and outstanding
4,912,249

 
4,859,048

Total Partners' Equity (Deficit)
(441,471
)
 
(531,587
)
Total Liabilities and Partners' Equity (Deficit)
$
2,396,915

 
$
2,942,764

    











See accompanying notes to financial statements.

25




Rockies Region 2007 Limited Partnership
Statements of Operations



 
Year Ended December 31,
 
2017
 
2016
Revenues:
 
 
 
Crude oil, natural gas and NGLs sales
$
1,246,713

 
$
1,592,710

 
 
 
 
Operating costs and expenses:
 
 
 
Lease Operating Expenses
639,923

 
884,273

Production Taxes
47,455

 
68,894

Transportation, gathering and processing expenses

 
23,998

Direct costs - general and administrative
173,095

 
172,582

Depreciation, depletion and amortization
278,158

 
410,300

Accretion of asset retirement obligations
183,446

 
191,727

Gain on recovery of sales tax refund
(121,348
)
 

Gain on settlement of asset retirement obligations, net
(13,099
)
 
(7,979
)
Total operating costs and expenses
1,187,630

 
1,743,795

 
 
 
 
Income (loss) from operations
59,083

 
(151,085
)
Interest income on sales tax refund
40,687

 

Net income (loss)
$
99,770

 
$
(151,085
)
 
 
 
 
Net income (loss)
$
99,770

 
$
(151,085
)
Less: Managing General Partner interest in net income (loss)
36,915

 
(55,901
)
Net income (loss) allocated to Investor Partners
$
62,855

 
$
(95,184
)
 
 
 
 
Investor Partner units outstanding
4,470

 
4,470

 
 
 
 
Net income (loss) per Investor Partner unit
$
14

 
$
(21
)

See accompanying notes to financial statements.

26


Rockies Region 2007 Limited Partnership
Statements of Partners' Equity (Deficit)
For the Years Ended December 31, 2017 and 2016



 
 
 
 
Managing
 
 
 
 
Investor
 
General
 
 
 
 
Partners
 
Partner
 
Total
 
 
 
 
 
 
 
Balance, December 31, 2015
 
$
5,211,304

 
$
(5,183,755
)
 
$
27,549

 
 
 
 
 
 
 
Distributions to partners
 
(257,072
)
 
(150,979
)
 
(408,051
)
 
 
 
 
 
 
 
Net loss
 
(95,184
)
 
(55,901
)
 
(151,085
)
 
 
 
 
 
 
 
Balance, December 31, 2016
 
4,859,048

 
(5,390,635
)
 
(531,587
)
 
 
 
 
 
 
 
Distributions on behalf of Investor Partners for withholding taxes
 
(9,654
)
 

 
(9,654
)
 
 
 
 
 
 
 
Net income
 
62,855

 
36,915

 
99,770

 
 
 
 
 
 
 
Balance, December 31, 2017
 
$
4,912,249

 
$
(5,353,720
)
 
$
(441,471
)



























See accompanying notes to financial statements.

27


Rockies Region 2007 Limited Partnership
Statements of Cash Flows



 
Year Ended December 31,
 
2017
 
2016
Cash flows from operating activities:
 
 
 
Net income (loss)
$
99,770

 
$
(151,085
)
Adjustments to net income (loss) to reconcile to net cash
   from operating activities:
 
 
 
Depreciation, depletion and amortization
278,158

 
410,300

Accretion of asset retirement obligations
183,446

 
191,727

Gain on settlement of asset retirement obligations
(13,099
)
 
(7,979
)
Gain on recovery of sales tax refund
(121,348
)
 

Changes in assets and liabilities:
 
 
 
Accounts receivable
129,984

 
(51,061
)
Crude oil inventory
(22,990
)
 
26,605

Asset retirement obligations
(1,064,335
)
 
(59,007
)
Due to Managing General Partner-other, net
78,815

 
194,917

Net cash (deficit) from operating activities
(451,599
)
 
554,417

Cash flows from investing activities:
 
 
 
Capital expenditures for crude oil and natural gas properties
(61,162
)
 
(66,179
)
Proceeds from the sale of crude oil and natural gas properties
143,447

 

Proceeds from the recovery of sales tax refund
160,547

 

Net cash from investing activities
242,832

 
(66,179
)
Cash flows from financing activities:
 
 
 
Distributions on behalf of Investor Partners for withholding taxes
(9,654
)
 
(3,621
)
Distributions to Partners

 
(404,430
)
Net cash from financing activities
(9,654
)
 
(408,051
)
 
 
 
 
Net change in cash and cash equivalents
(218,421
)
 
80,187

Cash and cash equivalents, beginning of period
576,132

 
495,945

Cash and cash equivalents, end of period
$
357,711

 
$
576,132

 
 
 
 
Supplemental disclosure of non-cash activity:
 
 
 
Change in asset retirement obligation, with corresponding
      change in crude oil and natural gas properties
$
185,784

 
$
470,085

Change in due to managing general partner-other, net
related to purchases and sales of properties and equipment
$
6,576

 
$

 
 
 
 






See accompanying notes to financial statements.

28


ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS






NOTE 1 - GENERAL

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

As of December 31, 2017, there were 1,756 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. The formula for the repurchase price is set at a minimum of four times the most recent 12 months of cash distributions. The Managing General Partner made repurchases of three limited partner units during the first quarter of 2017 at an average price of $197 per unit.

Due to the suspension of cash distributions, there is no value upon which to base further calculations, and therefore, no repurchase offers are currently being considered. On a cumulative basis, through December 31, 2017, the Managing General Partner had repurchased 153 units of Partnership interest from the Investor Partners at an average price of $2,258 per unit. As of December 31, 2017, the Managing General Partner owned approximately 39 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.

Certain immaterial reclassifications have been made to prior period financial statements to conform to the current period presentation. The reclassifications had no impact on previously reported financial results.

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 expenditures, plugging and abandonment of wells, and cash distributions to partners. This Partnership generated negative cash from operations of $452,000 for the year ended December 31, 2017, and had a working capital deficit of $826,000 as of December 31, 2017. The negative impact to its liquidity resulting from sustained depressed commodity prices, the negative impact of high line pressures on productivity, and decreasing production from natural declines raises substantial doubt about this Partnership’s ability to continue as a going concern. As the expected cash outlays for plugging and abandoning wells over the next several years are expected to be significant, this applies further pressure on the overall liquidity of this Partnership. The Managing General Partner believes that cash flows from operations will be insufficient to meet this Partnership’s obligations, largely because of ongoing expected declines in production volumes and the expenditures required to plug and abandon uneconomic wells, absent a change in circumstances as described below. This deficit in available cash flows generated by this Partnership's operations is currently being funded by the Managing General Partner to the extent necessary. The Managing General Partner will recover amounts funded from future cash flows of this Partnership, to the extent 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, equipment, operating costs, and plugging and abandonment costs, as well as monthly operating fees payable to the Managing General Partner. This Partnership's quarterly cash distributions to the Investor Partners and Managing General Partner were suspended beginning in the first quarter of 2017. This suspension in cash distributions, other than in connection with Investor Partners' tax withholding requirements, is expected to continue until such

29


time, if ever, that cash flows can reasonably be expected to support the necessary costs of expected plugging and abandoning of the wells that are becoming unproductive and any capital investments required for regulatory compliance, and this Partnership becomes current on its obligations.

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 and continued funding of cash flow deficits by the Managing General Partner. Greater cash flow would most likely occur from improved commodity pricing and, to a lesser extent, a sustained increase in production. 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 substantial amounts of capital expenditures.

The Managing General Partner is considering various options to potentially mitigate risks impacting 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 a partial or complete sale of assets. 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. See footnote Subsequent Event.

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

30


ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS - Continued

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 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 geologic, 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, a Level 3 fair value input, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairment charges would be included in the statement of operations line item "Impairment of crude oil and natural gas properties" with a corresponding reduction to the "Crude oil and natural gas properties" and "Accumulated depreciation, depletion, and amortization" line items on the balance sheets. There were no impairment charges for this Partnership for the years ended December 31, 2017 or 2016.

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 is recorded in the line item "Production Taxes" on this Partnership's statements of operations. This Partnership's production taxes payable are included in the line item "Due to Managing General Partner-other, net" on this Partnership's balance sheets.

Income Taxes. Since the taxable income or loss of this Partnership is reported in the tax returns of the individual investor partners, no provision has been made for income taxes for 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 associated 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 as a DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the long-lived asset and the asset retirement obligation. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations.


31


ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS - Continued

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. This Partnership's natural gas and NGLs are sold by the Managing General Partner on a long-term basis, primarily over the life of the well. The Managing General Partner's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and the quality of the natural gas. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. This Partnership uses the gross method of accounting for crude oil delivered through a certain pipeline as these purchasers do not provide transportation, gathering or processing services. Under this method, this Partnership recognizes revenues based on the gross selling price.

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 standard has been updated and now includes technical corrections. 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: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations, and (5) recognize revenue when or as each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; the Partnership is adopting the standard effective January 1, 2018. The revenue standard can be adopted under the full retrospective method or modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard will have on this Partnership’s financial statements, the Managing General Partner performed a comprehensive review of its significant revenue streams. The focus of this review included, among other things, the identification of the significant contracts and other arrangements this Partnership has with its customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of the transaction price. The Managing General Partner also reviewed this Partnership’s current accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if any, may be required by the adoption of the revenue standard. The Managing General Partner has determined that the Partnership will adopt the standard under the modified retrospective method. Based upon the review, the Managing General Partner currently estimates that adoption of the standard would not have impacted this Partnership’s 2017 results of operations and would have reduced this Partnerships crude oil, natural gas, and NGLs sales by approximately $24,000 in 2016, with a corresponding decrease in transportation, gathering, and processing expenses and no impact on net earnings. Upon adoption, no adjustment to this Partnership’s opening balance of retained deficit was deemed necessary.

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 Managing General Partner utilizes fair value, on a non-recurring basis, to perform impairment testing on this Partnership's crude oil and natural gas properties by comparing carrying value to estimated undiscounted future net cash flows.

32


ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS - Continued

If carrying value exceeds undiscounted future net cash flows, the measurement of impairment is based on estimated fair value and is measured by the amount by which the carrying value exceeds the estimated fair value.

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 these commodities 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 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, 2017 and 2016, this Partnership did not record an allowance for doubtful accounts and did not incur any losses on accounts receivable during the years then ended. As of December 31, 2017 and 2016, this Partnership had three customers representing 10 percent or more of the accounts receivable balance.

Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues:
 
 
Year ended December 31,
Major Customer
 
2017
 
2016
Suncor Energy Marketing, Inc.
 
38%
 
43%
DCP Midstream, LP
 
33%
 
21%
ARM Energy Management
 
21%
 
24%
Concord Energy, LLC
 
2%
 
10%

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,
 
2017
 
2016
 
 
 
 
Balance at beginning of period
$
2,908,509

 
$
2,313,683

Revisions in estimated cash flows
185,784

 
470,085

Obligations discharged with asset retirements
(1,064,335
)
 
(59,007
)
Accretion expense
183,446

 
191,727

Gain on settlement of asset retirement obligations
(13,099
)
 
(7,979
)
Balance at end of period
2,200,305

 
2,908,509

Less current portion
(750,000
)
 
(1,207,500
)
Long-term portion
$
1,450,305

 
$
1,701,009


This Partnership's estimated asset retirement obligations liability is based on its historical experience in plugging and abandoning, estimated economic lives and estimated plugging and abandonment costs considering federal and state regulatory requirements in effect. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. As of December 31, 2017, the credit-adjusted risk-free rates used to discount this Partnership's plugging and abandonment liabilities ranged from 6.5 percent to 7.5 percent. The revisions in estimated cash flows during 2017 were due to a decrease in the estimated useful lives of wells to be plugged and abandoned over the next twelve months, partially offset by the decrease in estimated costs for materials and services related to plugging and abandonment activity. The net result is 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 2016 were due to a decrease in the estimated useful life of these wells, which resulted

33


ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS - Continued

in an increase to the asset retirement obligation liability and a corresponding increase to crude oil and natural gas properties. The current portion of the asset retirement obligations relates to 15 wells that are expected to be plugged and abandoned within the next 12 months.

34


ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS - Continued

NOTE 7 - COMMITMENTS AND CONTINGENCIES

Legal Proceedings

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

Derivative Action

In December 2017, a derivate action was brought by certain limited partners of this Partnership against PDC as Managing General Partner of this Partnership. This action is entitled DuFresne, et al. v. PDC Energy, et al. and was filed in the United District Court for the District of Colorado. This action alleges claims for breach of fiduciary duty and breach of contract against PDC and two of its senior officers. The lawsuit accuses PDC of, among other things, failing to maximize the productivity of this Partnership’s crude oil and natural gas wells.

PDC filed a motion to dismiss the lawsuit on February 1, 2018, on the grounds that the complaint is deficient, including because the plaintiffs failure to allege that PDC refused a demand to take action on their claims. On March 14, 2018, the motion was denied by the court.

Environmental

Due to the nature of the oil and natural 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. Except as discussed below, the Managing General Partner is not aware of any material environmental claims existing as of December 31, 2017 which have not been provided for or would otherwise have a material impact on this Partnership's financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other potential sources of liability will not be discovered on this Partnership's properties. However, the liability ultimately incurred with respect to a matter may exceed the related accrual.

Clean Air Act Agreement and Related Consent Decree

In August 2015, the Managing General Partner received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of this Partnership's Wattenberg Field production facilities in the Denver-Julesburg Basin ("DJ Basin"). The Information Request focused on historical operation and design information at certain of the Managing General Partner's production facilities and asked that the Managing General Partner conduct sampling and analyses at these facilities. The Managing General Partner responded to the Information Request with the requested data in January 2016.
    
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 certain production facilities consistent with applicable standards under Colorado law.

In June 2017, the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, filed a complaint against the Managing General Partner in the U.S. District Court for the District of Colorado, claiming that the Managing General Partner failed to operate and maintain certain condensate collection systems at certain production facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, the Managing General Partner entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, the Managing General Partner agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system

35


ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS - Continued

modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects; (ii) injunctive relief; and (iii) mitigation.

The Managing General Partner will pay the total amount of the fine and costs associated with the supplemental environmental projects. This Partnership will share proportionally in the injunctive relief and the mitigation costs required by the consent decree. The consent decree includes 32 of this Partnership's wells, of which 18 are currently expected to incur such costs. The profitability of additional older, lower production wells, such as those owned by this Partnership, is likely to be affected in a negative manner by the required costs associated with the injunctive relief and mitigation, which could result in the decision to plug and abandon wells owned by this Partnership.

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. 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.

Unit Repurchase Provisions. Investor Partners may request that the Managing General Partner repurchase limited partnership units at any time beginning with the third anniversary of the first cash distribution of this Partnership. The repurchase price is set at a minimum of four times the most recent 12 months of cash distributions from production. In accordance with the Partnership Agreement, the Managing General Partner has elected to suspend cash distributions in order to fund the plugging and abandonment costs of 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 the suspension of cash distributions the Managing General Partner is currently unable to repurchase units as there is expected to be no value upon which to base the calculation. Previously, in any calendar year the Managing General Partner was 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.


36


ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS - Continued

Cash Distributions

The Agreement requires the Managing General Partner to distribute available cash for distribution no less frequently than quarterly, if available. However, as the wells have gotten older and the likelihood of plugging and abandonment activities in the foreseeable future has increased, 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 obligations. As a result of the impact to the cash distribution policy, if cash were to become available in excess of the plugging and abandonment obligations, 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 2008. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:
 
 
Years Ended December 31,
 
 
2017
 
2016
 
 
 
 
 
Distributions on behalf of Investor Partners for withholding taxes
 
$
9,654

 
$
3,621

Distributions to Partners
 

 
404,430

Cash distributions
 
$
9,654

 
$
408,051

 
 
 
 
 


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 this Partnership, net of corresponding operating costs and other cash outflows incurred on behalf of this Partnership.

This Partnership's net amount due to the Managing General Partner was approximately $638,000 and $566,000 as of December 31, 2017 and December 31, 2016, respectively. The majority of the amount due represents operating costs, plugging and abandonment costs, and general and administrative and other costs that have not been deducted from distributions.

A “Well operations and maintenance” fee is charged by the Managing General Partner for the operation of this Partnership's wells and is included in the “Lease operating expenses” line item in the statements of operations. The fees for well operating and maintenance for the twelve months ended December 31, 2017 and December 31, 2016 were approximately $250,000 and $356,000, respectively. The decrease in fees during twelve months ended December 31, 2017 compared to 2016 is due to a decrease in the number of wells for which this Partnership is charged the fee.
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.

37


ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS - Continued

These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has provided and may in the future provide equipment or supplies, salt water disposal 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 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 and 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;
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 are on terms no less favorable than could have been obtained from non-affiliated third parties.
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.
The Agreement provides for the allocation of cash distributions 63 percent to the Investors Partners and 37 percent to the Managing General Partner. The investor Partner cash distributions during the years ended December 31, 2017 and 2016 include $331 and $8,407, respectively, related to equity cash distributions for Investor Partner units that have been repurchased by PDC.

NOTE 10 - SALES TAX REFUND

In 2017, the Managing General Partner recently received a refund totaling $201,000 of previously-remitted refund requests for state sales and use tax related to wells this Partnership drilled and equipped in 2008 and related interest due to the Partnership. Of the amount refunded, $49,000 related to a portion of this Partnership’s wells in the Wattenberg Field and $152,000 related to wells in the Piceance Basin. Of the amount received related to wells in the Wattenberg Field, $39,000 was related to tangible well equipment and, accordingly, was recorded against the balance of crude oil and natural gas properties and $10,000 was recorded as interest income. Because this Partnership no longer owns the Piceance Basin wells, the sales tax refund totaling $121,000 previously paid on the tangible well equipment was recorded to the income statement as gain on recovery of sales tax refund and $31,000 was recorded as interest income.


38


ROCKIES REGION 2007 LIMITED PARTNERSHIP
Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited


Net Proved Reserves

All of this Partnership's crude oil, natural gas and NGLs reserves are located in the U.S. This Partnership utilized the services of an independent petroleum engineer to estimate this Partnership's 2017 and 2016 crude oil, natural gas, and NGLs reserves. As of December 31, 2017 and 2016, 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 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, 2017 and 2016, there are no proved undeveloped reserves for this Partnership.

The following table presents the index prices 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)
2017
 
$
51.34

 
$
2.98

 
$
51.34

2016
 
42.75

 
2.48

 
42.75


The following table presents the net-back price used to estimate our 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)
2017
 
$
48.74

 
$
2.32

 
$
16.56

2016
 
38.70

 
1.96

 
10.21

 


39


ROCKIES REGION 2007 LIMITED PARTNERSHIP
Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited

The following table presents the changes in estimated quantities of this Partnership's reserves:
 
Crude Oil and Condensate
 
Natural Gas
 
NGLs
 
Crude Oil Equivalent
 
(MBbl)
 
(MMcf)
 
(MBbl)
 
(MBoe)
Proved Reserves:
 
 
 
 
 
 
 
Proved reserves, January 1, 2016
107

 
487

 
58

 
246

Revisions of previous estimates and reclassifications
32

 
190

 
27

 
91

Production
(32
)
 
(132
)
 
(17
)
 
(71
)
Proved reserves, December 31, 2016
107

 
545

 
68

 
266

Revisions of previous estimates and reclassifications
(15
)
 
(30
)
 
(2
)
 
(22
)
Production
(17
)
 
(99
)
 
(12
)
 
(46
)
Proved reserves, December 31, 2017
75

 
416

 
54

 
198

 
 
 
 
 
 
 
 
Proved Developed Reserves, as of:
 
 
 
 
 
 
 
December 31, 2016
107

 
545

 
68

 
266

December 31, 2017
75

 
416

 
54

 
198

 
 
 
 
 
 
 
 

2017 Activity. As of December 31, 2017, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 22 MBoe. The revision includes downward revisions to previous estimates of 15 MBbl of crude oil, 30 MMcf of natural gas, and 2 MBbl of NGLs. The downward revisions were the result of high line pressures on the gas gathering facilities and the natural decline rates of this Partnership's wells, partially offset by increased pricing. There were no proved undeveloped reserves developed in 2017 and no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2017.

2016 Activity. As of December 31, 2016, this Partnership recorded an upward revision of its previous estimate of proved reserves by approximately 91 MBoe. The revision includes upward revisions to previous estimates of 32 MBbl of crude oil, 190 MMcf of natural gas, and 27 MBbl of NGLs. The upward revisions were the result of reductions in gathering system line pressures. 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.
  
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.
    
    

40


ROCKIES REGION 2007 LIMITED PARTNERSHIP
Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited

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 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,
 
2017
 
2016
Future estimated cash flows
$
5,529,700

 
$
5,891,400

Future estimated production costs
(3,671,900
)
 
(3,836,000
)
Future estimated abandonment costs
(1,994,600
)
 
(3,696,400
)
Future net cash flows
(136,800
)
 
(1,641,000
)
10% annual discount for estimated timing of cash flows
173,800

 
762,100

Standardized measure of discounted future estimated net cash flows
$
37,000

 
$
(878,900
)

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. Drilling operations began upon funding in August 2007. This Partnership currently owns an undivided working interest in 53 gross (51.9 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,
 
2017
 
2016
Crude oil and natural gas properties, successful efforts method, at cost
$
4,413,455

 
$
4,355,731

Less: Accumulated DD&A
(2,578,345
)
 
(2,300,187
)
Crude oil and natural gas properties, net
$
1,835,110

 
$
2,055,544


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.



41


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

None.

ITEM 9A. CONTROLS AND PROCEDURES

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

(a) Evaluation of Disclosure Controls and Procedures

As of December 31, 2017, PDC, as Managing General Partner on behalf of this Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of this Partnership's disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that this Partnership files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC's rules and forms, and that such information is accumulated and communicated to this Partnership's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.

Management of the Managing General Partner is responsible for internal control over financial reporting of this Partnership as this Partnership shares the Managing General Partner's disclosure controls and procedures. As of December 31, 2017, the Managing General Partner carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Managing General Partner’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, its Chief Executive Officer and Chief Financial Officer concluded that the Managing General Partner’s disclosure controls and procedures were not effective as of December 31, 2017 because of material weaknesses in its internal control over financial reporting. The material weaknesses identified by management of the Managing General Partner did not impact this Partnership’s disclosure controls and procedures during any periods covered by this report.
Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and Chief Financial Officer concluded that this Partnership's disclosure controls and procedures were effective as of December 31, 2017.

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

Management of PDC, the Managing General Partner, 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.

42




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, 2017, 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, 2017.

Exchange Act Rules 13a-15(c) and 15d - 15(c) and Section 404 of the Sarbanes-Oxley Act of 2002 require management of this Partnership to conduct an annual evaluation of this Partnership's internal control over financial reporting and to provide a report on management's assessment, including a statement as to whether or not internal control over financial reporting is effective. Since this Partnership is neither an accelerated filer nor a large accelerated filer as defined by SEC regulations, this Partnership's internal control over financial reporting was not subject to attestation by this Partnership's independent registered public accounting firm. As such, this Annual Report on Form 10-K does not contain an attestation report of this Partnership's independent registered public accountant regarding internal control over financial reporting.

(c) Changes in Internal Control over Financial Reporting
During the three months ended December 31, 2017, 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.



43




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 its business through the D&O Agreement. PDC's directors and executive officers and other employees receive direct remuneration, compensation or reimbursement solely from PDC, and not this Partnership, with respect to services rendered in their capacity to act on behalf of this Partnership.

Board Management and Risk Oversight

PDC, a publicly traded Delaware corporation, was organized in Nevada in 1955 and reincorporated to Delaware in 2015. The common stock of PDC is traded on the NASDAQ Global Select Market under the symbol "PDCE." The business and affairs of this Partnership are managed by the Managing General Partner through the D&O Agreement, by or under the direction of the PDC Board of Directors (the "Board"), 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 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 Board has established the Audit Committee, including a sub-committee 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

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 and principal financial 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, 2017, no person subject to the requirements of Section 16(a) under the Securities Exchange Act of 1934 failed to file a report required thereunder.


44




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.
 
55
 
President, Chief Executive Officer and Director
 
2015
 
2019
 
 
 
 
 
 
 
 
 
R. Scott Meyers
 
43
 
Senior Vice President and Chief Financial Officer
 
 
 
 
 
 
 
 
 
 
 
Lance Lauck
 
55
 
Executive Vice President Corporate Development and Strategy
 
 
 
 
 
 
 
 
 
 
 
Scott J. Reasoner
 
57
 
Chief Operating Officer
 
 
 
 
 
 
 
 
 
 
 
Daniel W. Amidon
 
57
 
Senior Vice President, General Counsel and Secretary
 
 
 
 
 
 
 
 
 
 
 
Jeffrey C. Swoveland
 
63
 
Non-Executive Chairman
 
1991
 
2020
 
 
 
 
 
 
 
 
 
Christina M. Ibrahim
 
50
 
Director
 
2018
 
2018
 
 
 
 
 
 
 
 
 
Anthony J. Crisafio
 
65
 
Director
 
2006
 
2018
 
 
 
 
 
 
 
 
 
Larry F. Mazza 
 
57
 
Director
 
2007
 
2019
 
 
 
 
 
 
 
 
 
David C. Parke
 
51
 
Director
 
2003
 
2020
 
 
 
 
 
 
 
 
 
Mark E. Ellis
 
61
 
Director
 
2017
 
2019
 
 
 
 
 
 
 
 
 
Randy S. Nickerson
 
56
 
Director
 
2017
 
2018

Barton R. Brookman, Jr., PDC's President and Chief Executive Officer ("CEO"), was appointed to the Board in January 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.

R. Scott Meyers was appointed to PDC's Senior Vice President and Chief Financial Officer in January 2018. Prior to that, he served as Chief Accounting Officer beginning in April of 2009. Prior to joining the Company, Mr. Meyers served as a Senior Manager with Schneider Downs Co. Inc., an accounting firm based in Pittsburgh, Pennsylvania. Mr. Meyers served in such capacity from April 2008 to March 2009. Prior thereto from November 2002 to March 2008 Mr. Meyers was employed by PricewaterhouseCoopers LLP, the last two and one-half years serving as Senior Manager. Mr. Meyers holds a Bachelor of Science degree in Accounting from Grove City College, Pennsylvania.


45




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 and 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. Before joining PDC, he served as a Business Unit Manager with Noble Energy Inc. ("Noble") where he was responsible for the Mid-Continent team. Prior to his work with Noble, 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 graduated from 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. Meyers 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.

Jeffrey C. Swoveland, a National Association of Corporate Directors Board Leadership Fellow, joined 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, Inc. from 2006 to 2017.
Christina M. Ibrahim joined the Board in January 2018. Ms. Ibrahim currently serves as the Executive Vice President, General Counsel and Chief Compliance Officer of Weatherford International plc (“Weatherford”), a position she has held since May 2015. Prior to joining Weatherford in 2015, Ms. Ibrahim held a number of senior leadership positions of increasing responsibility in the legal department of Halliburton Company since January 2010, including, most recently, as Vice President, Chief Commercial Counsel and Corporate Secretary with responsibility for the global procurement, employment and real estate practice groups and oversight of mergers and acquisitions, securities, regulatory and governance practice groups. Ms. Ibrahim also served as General Counsel and Chief Compliance Officer for WellDynamics, a Halliburton joint venture company.

Anthony J. Crisafio, a Certified Public Accountant ("CPA") and a National Association of Corporate Directors Board Leadership Fellow, joined 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 has 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, and TruFoodMfg. 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 has served as an Advisory Board member for a number of privately held companies.


46




Larry F. Mazza, a CPA, joined 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 joined 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.

Mark E. Ellis joined the Board in September 2017. Mr. Ellis currently serves as a director and as the President and Chief Executive Officer of Linn Energy, Inc. ("Linn"), positions he has held since February 2017. From January 2010 until February 2017, Mr Ellis was the President and Chief Executive Officer of Linn Energy LLC. Linn is the reorganized successor to Linn Energy LLC, which filed for bankruptcy in the federal bankruptcy court, Southern District of Texas in May, 2016. From 2012 to February 2017, Mr. Ellis also served as Chairman of Linn Energy LLC's board of directors. Prior to joining Linn in 2006, Mr. Ellis served in varying roles of increasing responsibility for Burlington Resources and ConocoPhillips.

Randy S. Nickerson joined the Board in March 2017.  Mr. Nickerson most recently served as the Executive Vice President, Corporate Strategy of Marathon Petroleum Corporation and as the Executive Vice President and Chief Commercial Officer of the MarkWest assets of MPLX LP since December 2015. Prior to joining Marathon Petroleum Corporation, Mr. Nickerson served in various capacities of increasing responsibility for MarkWest Energy Partners, L.P. and its predecessor, including most recently as its Senior Vice President, Corporate Development and Chief Commercial Officer from 2006 until December 2015. 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 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. Anthony J. Crisafio chairs the Audit Committee. Other members are Directors Swoveland and Parke. The Board has determined that all 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. Any management fees 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 fees were paid to PDC in 2017 or 2016 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, 2017, concerning the Managing General Partner's interest in this Partnership and other persons known by this Partnership to own beneficially more than 5 percent of the interests in this Partnership, if any. Each partner exercises sole voting and investing power with respect to the interest beneficially owned.
 
Limited Partnership Units
 
 
 
Number of
 
Number of Units Beneficially Owned
 
Percentage of Total Units Outstanding
 
 Percentage of
 
Units
 
 
 
Total Partnership
 
Outstanding Which
 
 
 
Interests
 
Represent 63% of Total
 
 
 
Beneficially
Person or Group
Partnership Interests (1)
 
 
 
Owned
 
4,470.00

 
 
 
 
 
 
PDC Energy, Inc. (2) (3) (4) (5)

 
153.3

 
3.43
%
 
2.16
%

(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

47




repurchased by PDC to total limited partnership units, by the limited partners' percentage ownership in this Partnership. [(153.3 units/4,470 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.


48




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
 
2017
 
2016
Schneider Downs Audit Fees (1)
 
$
114,000

 
$
91,000

PwC Audit Fees (1)
 

 
20,000

PwC Audit-Related Fees (2)
 

 
15,000

Total Fees
 
$
114,000

 
$
126,000


(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 Audit 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.

49





PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)    The index to Financial Statements is located on page 23.
(b)    Exhibits index.

 
 
 
 
Incorporated by Reference
 
 

Exhibit
Number
 
Exhibit Description
 
Form
 

SEC File
Number
 
Exhibit
 
Filing Date
 

Filed
Herewith
3.1
 

 
10-12G/A Amend 1

 
000-53201
 
3
 
08/06/2008
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.2
 
 
10-12G/A Amend 1

 
000-53201
 
3.1
 
08/06/2008
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.1
 
 
10-12G/A Amend 1
 
000-53201
 
10.2
 
08/06/2008
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.2
 
 
10-12G/A Amend 1
 
000-53201
 
10.1
 
08/06/2008
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
31.1
 
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
31.2
 
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
32.1
 
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 

50




 
 
 
 
Incorporated by Reference
 
 

Exhibit
Number
 
Exhibit Description
 
Form
 

SEC File
Number
 
Exhibit
 
Filing Date
 

Filed
Herewith
99.1
 

 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
99.2
 
 
10-K
 
001-37419
 
 
 
02/27/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.INS
 
XBRL Instance Document
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema Document
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 


51




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 2007 Limited Partnership
By its Managing General Partner
PDC Energy, Inc.

 
By: /s/ Barton R. Brookman, Jr.
 
 
Barton R. Brookman, Jr.
President, Chief Executive Officer and Director
of PDC Energy, Inc.
 
 
March 29, 2018
 
 
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:

52




Signature
 
Title
Date
/s/ Barton R. Brookman, Jr.
 
President, Chief Executive Officer and Director

March 29, 2018
Barton R. Brookman, Jr.

 
PDC Energy, Inc. Managing General Partner of the Registrant
 
 
 
(principal executive officer)
 
 
 
 
 
/s/ R. Scott Meyers
 
Senior Vice President and Chief Financial Officer
March 29, 2018
R. Scott Meyers
 
PDC Energy, Inc. Managing General Partner of the Registrant
 
 
 
(principal financial officer)
 
 
 
 
 
/s/Jeffrey C. Swoveland
 
Chairman and Director

March 29, 2018
Jeffrey C. Swoveland

 
PDC Energy, Inc.

 
 
 
Managing General Partner of the Registrant

 
 
 
 
 
/s/ Anthony J. Crisafio
 
Director

March 29, 2018
Anthony J. Crisafio
 
PDC Energy, Inc.

 
 
 
Managing General Partner of the Registrant

 
 
 
 
 
/s/ Larry F. Mazza
 
Director

March 29, 2018
Larry F. Mazza

 
PDC Energy, Inc.

 
 
 
Managing General Partner of the Registrant

 
 
 
 
 
/s/ David C. Parke
 
Director

March 29, 2018
David C. Parke
 
PDC Energy, Inc.

 
 
 
Managing General Partner of the Registrant

 
 
 
 
 
/s/ Randy S. Nickerson
 
Director

March 29, 2018
Randy S. Nickerson
 
PDC Energy, Inc.

 
 
 
Managing General Partner of the Registrant

 
 
 
 
 
/s/ Mark E. Ellis
 
Director

March 29, 2018
Mark E. Ellis
 
PDC Energy, Inc.

 
 
 
Managing General Partner of the Registrant

 
 
 
 
 
/s/ Christina M. Ibrahim
 
Director

March 29, 2018
Christina M. Ibrahim
 
PDC Energy, Inc.

 
 
 
Managing General Partner of the Registrant

 

53