10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

OF 1934

For the quarterly period ended September 30, 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

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 xNo £

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 x No £

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  o	Accelerated filer  o
Non-accelerated filer  o (Do not check if a smaller reporting company)	Smaller reporting company  x
	Emerging growth company  o

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. o

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

As of September 30, 2017, this Partnership had 4,470 units of limited partnership interest and no units of additional general partnership interest outstanding.

Rockies Region 2007 Limited Partnership

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements
	Condensed Balance Sheets (unaudited)	3
	Condensed Statements of Operations (unaudited)	4
	Condensed Statement of Partners' Equity (Deficit) (unaudited)	5
	Condensed Statements of Cash Flows (unaudited)	6
	Notes to Unaudited Condensed Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	18
Item 4.	Controls and Procedures	18
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	19
Item 1A.	Risk Factors	19
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	19
Item 3.	Defaults Upon Senior Securities	19
Item 4.	Mine Safety Disclosures	19
Item 5.	Other Information	19
Item 6.	Exhibits	21
	SIGNATURES	22

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 regarding this Partnership's business, financial condition, and results of operations. PDC Energy, Inc. (“PDC”) is the Managing General Partner of this Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates, and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements may relate to, among other things: future production (including the components of such production), sales, expenses, cash flows, and liquidity; estimated crude oil, natural gas, and natural gas liquids ("NGLs") reserves; 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 and the risk of an extended period of depressed prices;

• impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement 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;

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

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

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

Further, this Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this Quarterly Report on Form 10-Q, this Partnership's Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”) filed with the U.S. Securities and Exchange Commission (“SEC”) on March 28, 2017 and this Partnership's

- 1-

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.

- 2-

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Rockies Region 2007 Limited Partnership

Condensed Balance Sheets

(unaudited)

	September 30, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	841,004		$	576,132
Accounts receivable	156,913			296,635
Crude oil inventory	33,960			14,453
Total current assets	1,031,877			887,220
Crude oil and natural gas properties, successful efforts method, at cost	4,152,109			4,355,731
Less: Accumulated depreciation, depletion, and amortization	(2,520,363		)	(2,300,187		)
Crude oil and natural gas properties, net	1,631,746			2,055,544
Total Assets	$	2,663,623		$	2,942,764
Liabilities and Partners' Equity (Deficit)
Current liabilities:
Due to Managing General Partner-other, net	$	971,670		$	565,842
Current portion of asset retirement obligations	900,000			1,207,500
Total current liabilities	1,871,670			1,773,342
Asset retirement obligations	1,049,602			1,701,009
Total Liabilities	2,921,272			3,474,351
Commitments and contingent liabilities
Partners' equity (deficit):
Managing General Partner	(5,285,706		)	(5,390,635		)
Limited Partners - 4,470 units issued and outstanding	5,028,057			4,859,048
Total Partners' Equity (Deficit)	(257,649		)	(531,587		)
Total Liabilities and Partners' Equity (Deficit)	$	2,663,623		$	2,942,764

See accompanying notes to unaudited condensed financial statements.

- 3-

Rockies Region 2007 Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017			2016
Revenues:
Crude oil, natural gas, and NGLs sales	$	226,545		$	448,702	$	1,035,108		$	1,128,862
Operating costs and expenses:
Lease operating expenses	149,123			172,110		482,984			695,678
Production taxes	7,606			16,451		41,993			41,742
Transportation, gathering and processing expenses	—			—		—			18,292
Direct costs - general and administrative	27,482			51,085		102,858			108,501
Depreciation, depletion, and amortization	56,070			98,692		220,176			311,404
Accretion of asset retirement obligations	35,055			48,750		150,390			143,329
Gain on recovery of sales tax refund	(121,348		)	—		(121,348		)	—
Gain on settlement of asset retirement obligations	(84,850		)	—		(84,850		)	—
Total operating costs and expenses	69,138			387,088		792,203			1,318,946
Income (loss) from operations	157,407			61,614		242,905			(190,084		)
Interest income on sales tax refund	40,687			—		40,687			—
Net income (loss)	$	198,094		$	61,614	$	283,592		$	(190,084	)
Net income (loss) allocated to partners	$	198,094		$	61,614	$	283,592		$	(190,084	)
Less: Managing General Partner interest in net income (loss)	73,295			22,797		104,929			(70,331		)
Net income (loss) allocated to Investor Partners	$	124,799		$	38,817	$	178,663		$	(119,753	)
Net income (loss) per Investor Partner unit	$	27.92		$	8.68	$	39.97		$	(26.79	)
Investor Partner units outstanding	4,470			4,470		4,470			4,470

See accompanying notes to unaudited condensed financial statements.

- 4-

Rockies Region 2007 Limited Partnership

Condensed Statement of Partners' Equity (Deficit)

(unaudited)

	Nine Months Ended September 30, 2017
				Managing
	Investor			General
	Partners			Partner			Total
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	178,663			104,929			283,592
Balance, September 30, 2017	$	5,028,057		$	(5,285,706	)	$	(257,649	)

See accompanying notes to unaudited condensed financial statements.

- 5-

Rockies Region 2007 Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	283,592		$	(190,084	)
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	220,176			311,404
Accretion of asset retirement obligations	150,390			143,329
Gain on settlement of asset retirement obligations	(84,850		)	—
Gain on recovery of sales tax refund	(121,348		)	—
Changes in assets and liabilities:
Accounts receivable	139,722			(45,949		)
Crude oil inventory	(19,507		)	21,247
Asset retirement obligations	(860,455		)	—
Due to Managing General Partner-other, net	560,039			(5,845		)
Net cash from operating activities	267,759			234,102
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	(47,229		)	(46,029		)
Proceeds from sale of crude oil and natural gas properties	14,797			—
Proceeds from the recovery of sales tax refund	39,199			—
Net cash from investing activities	6,767			(46,029		)
Cash flows from financing activities:
Distributions on behalf of Investor Partners for withholding taxes	(9,654		)	(3,621		)
Distributions to Partners	—			(212,112		)
Net cash from financing activities	(9,654		)	(215,733		)
Net change in cash and cash equivalents	264,872			(27,660		)
Cash and cash equivalents, beginning of period	576,132			495,945
Cash and cash equivalents, end of period	$	841,004		$	468,285
Supplemental cash flow information:
Change in due to Managing General Partner-other, net related to proceeds from sales tax refund	$	121,348		$	—
Change in asset retirement obligation, with corresponding change in       crude oil and natural gas properties	(163,992		)	—
Change in due to managing general partner-other, net related to purchases and sales of properties and equipment	32,863			—

See accompanying notes to unaudited condensed financial statements.

- 6-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

Note 1 - General and Basis of Presentation

Rockies Region 2007 Limited Partnership (this “Partnership” or the “Registrant”) 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 Drilling and Operating Agreement (“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 Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of this Partnership and initiates and completes substantially all Partnership transactions.

As of September 30, 2017, there were 1,756 limited partners ("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. Due to the suspension of cash distributions during the first quarter of 2017, there is no value upon which to base the calculation, and therefore, no repurchase offers are currently being considered. On a cumulative basis, through September 30, 2017, the Managing General Partner has repurchased 153 units of Partnership interest from the Investor Partners at an average price of $2,258 per unit. As of September 30, 2017, the Managing General Partner owned approximately 39 percent of this Partnership, including the repurchased units. The Managing General Partner made no limited partner unit repurchases during the three months ended September 30, 2017.

In the Managing General Partner's opinion, the accompanying condensed financial statements contain all adjustments consisting of only normal recurring adjustments necessary for a fair statement of this Partnership's results for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 8 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The December 31, 2016, condensed balance sheet data was derived from this Partnership's audited financial statements, but does not include disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with this Partnership's audited financial statements and notes thereto included in this Partnership's 2016 Form 10-K. This Partnership's accounting policies are described in the Notes to Financial Statements in this Partnership's 2016 Form 10-K and updated, as necessary, in this Quarterly Report on Form 10-Q. The results of operations and cash flows for the nine months ended September 30, 2017, are not necessarily indicative of the results to be expected for the full year or any future period.

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. While this Partnership generated positive cash from operations for the nine months ended September 30, 2017, this Partnership had working capital deficits of $840,000 and $886,000 as of September 30, 2017 and December 31, 2016, respectively. The negative impact to its cumulative lack of liquidity resulting from sustained depressed commodity prices, the negative impact of high line pressures on the productivity and decreasing production from natural declines of the wells in this Partnership 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 is expected to amount to meaningful expenditures, this applies further pressure on the overall liquidity of this Partnership. The Managing General

- 7-

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 reimbursements of 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 Investor Partners' tax withholding requirements, is expected to remain in place until such time, if at all, 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.

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. Historically, as a result of the normal production decline in a well's production life cycle, this Partnership has not experienced a sustained increase in production without 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.

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

Recently Issued Accounting Standards    

In May 2014, the Financial Accounting Standards Board ("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; we are 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 consolidated financial statements, the Managing General Partner is performing a comprehensive review of this Partnership's significant revenue streams. The focus of this review includes, among other things, the identification of the significant contracts and other arrangements this Partnership have with its customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of transaction price. The Managing General Partner is also reviewing 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 this Partnership will adopt the standard under the modified

retrospective method. The Managing General Partner has not made a complete determination regarding the impact that the adoption will have on this Partnership's consolidated financial statements as of the time of this filing.

Note 4 - Fair Value Measurements

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

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. 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.

- 8-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

Note 5 - Asset Retirement Obligations

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

	Amount
Balance at December 31, 2016	$	2,908,509
Revisions in estimated cash flows	(163,992		)
Obligations discharged with asset retirements and expenditures	(860,455		)
Accretion expense	150,390
Gain on settlement of asset retirement obligations	(84,850		)
Balance at September 30, 2017	1,949,602
Less current portion	(900,000		)
Long-term portion	$	1,049,602

This Partnership's estimated asset retirement obligations liability is based on the Managing General Partner's historical experience in plugging and abandoning this Partnership's wells, estimated economic lives and estimated plugging and abandonment costs considering federal and state regulatory requirements in effect. Prior to 2017, this Partnership's plugging and abandonment activity had been limited; however, during the nine months ended September 30, 2017, this Partnership plugged 17 wells. Based on the 2017 plugging and abandonment activities, this Partnership's estimated future plugging and abandonment costs have been adjusted downward by approximately $164,000 as reflected in the table above. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. As of September 30, 2017, the credit-adjusted risk-free rates used to discount this Partnership's plugging and abandonment liabilities ranged from 6.5 percent to 8.2 percent. In periods subsequent to initial measurement of the liability, this Partnership must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors and changes to this Partnership's credit-adjusted risk-free rate as market conditions warrant.

During the three and nine months ended September 30, 2017, this Partnership plugged and abandoned 17 wells for a total estimated cost of approximately $860,000. These costs were offset by the release of the asset retirement obligations liability of approximately $945,000, resulting in a gain on settlement of asset retirement obligations of approximately $85,000.  The current portion of the asset retirement obligations relates to 18 wells that are expected to be plugged and abandoned during the next 12 months.

Note 6 - Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the oil and 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 September 30, 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 Tentative 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") of Colorado. 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 the facilities. The Managing General Partner responded with the requested data to the Information Request 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 (“CDPHE”) 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.

For more than a year, the Managing General Partner held a series of meetings with the EPA, Department of Justice (“DOJ”) and CDPHE on the above matters. On June 26, 2017, the DOJ on behalf of the EPA, and the State of Colorado filed a complaint against PDC based on the above matters.

A consent decree resolving the matter was signed by all parties on October 31, 2017 and is subject to a 30-day comment period, which will be publicly published in the Federal Register. The consent decree provides that the Managing General Partner will implement changes to the design, operation, and maintenance of most of its field-wide storage tank systems to enhance the emission management in the DJ Basin.  Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure

- 9-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

monitors.  The three primary elements of the tentative settlement 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 cost associated with supplemental environmental projects. This Partnership will share proportionally in the injunctive relief and may share in the mitigation efforts required by the consent decree. The consent decree includes substantially all of this Partnership’s wells located across 26 production facilities. The profitability of older low-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 decisions to plug additional wells owned by this Partnership.

Note 7 - 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 $972,000 and $566,000 as of September 30, 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 on the condensed statements of operations. The fees for well operating and maintenance for the three and nine months ended September 30, 2017 were approximately $56,000 and $203,000, respectively. The fees for well operating and maintenance for the three and nine months ended September 30, 2016 were approximately $85,000 and $258,000, respectively. The decrease in fees in during three and nine months ended September 30, 2017 periods compared to 2016 is due to a decrease in the number of wells for which this Partnership is charged the fee.

Note 8 - Sales Tax Refund

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 relates to a portion of this Partnership’s wells in the Wattenberg Field and $152,000 is related to wells previously owned by this Partnership in the Piceance Basin. This Partnership sold the wells in the Piceance Basin in 2013. 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 to the income statement as gain on recovery of sales tax refund and $31,000 was recorded as interest income.

- 10-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Partnership Overview

This Partnership engages in the development, production, and sale of crude oil, natural gas, and NGLs. This Partnership began crude oil and natural gas operations in August 2007 and currently operates 56 gross (54.9 net) wells located in the Wattenberg Field of Colorado. The Managing General Partner markets this Partnership's crude oil, natural gas, and NGL production to midstream marketers. Crude oil, natural gas, and NGLs are sold primarily under market-based contracts in which the price varies as a result of market forces. PDC does not charge a separate fee for the marketing of the crude oil, natural gas, and NGLs because these services are covered by a monthly well operating charge. Seasonal factors, such as effects of weather on realized commodity prices, availability of third-party owned pipeline capacity, and other factors such as high line pressures in the gathering system, whether caused by heat or third-party capacity issues, may impact this Partnership's results.

Partnership Operating Results Overview

This Partnership’s operations for the three and nine months were impacted by a number of noteworthy items. Aggregate crude oil, natural gas, and NGLs production, decreased 46 percent and 30 percent for the three and nine months ended September 30, 2017, respectively, compared to the three and nine months ended September 30, 2016. Crude oil production decreased 60 percent and 41 percent for the comparable three and nine month periods of 2016, respectively. The primary drivers for the continued decrease in production include increasingly high gathering system line pressures, fewer producing wells resulting from ongoing plugging and abandonment activity, 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 remain elevated.

This Partnership’s plugging and abandonment activities were initiated during the three and nine months ended September 30, 2017, and involved 17 wells with estimated costs totaling $860,000. These 17 wells were plugged and abandoned as they were expected to be uneconomic to operate given anticipated capital spending levels that would be required to meet newly-implemented environmental standards. There were no plugging and abandonment activities for the comparable nine month period ended September 30, 2016.

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, as well as the gain on the recovery of sales tax refund and interest income.

When considering the current commodity price environment, the significantly increased line pressure along with the ongoing operating costs, production taxes, direct costs - general and administrative, as well as 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. Accordingly, in the first quarter 2017, this Partnership 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. 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.

- 11-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

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

	Three months ended September 30,						Nine months ended September 30,
	2017		2016		Change		2017		2016			Change
Number of gross productive wells (end of period) (1)	56		75		(25	)%	56		75			(25	)%
Production
Crude oil (Bbl)	3,187		7,924		(60	)%	14,874		25,042			(41	)%
Natural gas (Mcf)	21,220		30,655		(31	)%	77,726		100,757			(23	)%
NGLs (Bbl)	2,494		4,016		(38	)%	10,099		12,410			(19	)%
Crude oil equivalent (Boe)	9,218		17,049		(46	)%	37,927		54,245			(30	)%
Average Boe per day	100		185		(46	)%	139		198			(30	)%
Crude oil, natural gas, and NGLs sales
Crude oil	$	144,406	$	348,994	(59	)%	$	709,103	$	922,852		(23	)%
Natural gas	43,061		61,760		(30	)%	174,138		159,131			9	%
NGLs	39,078		37,948		3	%	151,867		110,141			38	%
Provision for underpayment of natural gas sales	—		—		*		—		(63,262		)	*
Total crude oil, natural gas, and NGLs sales	$	226,545	$	448,702	(50	)%	$	1,035,108	$	1,128,862		(8	)%
Average selling price
Crude oil (per Bbl)	$	45.31	$	44.04	3	%	$	47.67	$	36.85		29	%
Natural gas (per Mcf)	$	2.03	$	2.01	1	%	$	2.24	$	1.58		42	%
NGLs (per Bbl)	$	15.67	$	9.45	66	%	$	15.04	$	8.88		69	%
Crude oil equivalent (per Boe)	$	24.58	$	26.32	(7	)%	$	27.29	$	21.98		24	%
Average cost per Boe
Lease operating expenses	$	16.17	$	10.10	60	%	$	12.73	$	12.82		(1	)%
Production taxes	0.83		0.96		(14	)%	1.11		0.77			44	%
Transportation, gathering and processing expenses	—		—		*		—		0.34			*
Total production costs	$	17.00	$	11.06	54	%	$	13.84	$	13.93		(1	)%
Depreciation, depletion and amortization (per Boe)	$	6.08	$	5.79	5	%	$	5.81	$	5.74		1	%
Operating costs and expenses
Lease operating expenses	$	149,123	$	172,110	(13	)%	$	482,984	$	695,678		(31	)%
Production taxes	7,606		16,451		(54	)%	41,993		41,742			1	%
Transportation, gathering and processing expenses	—		—		*		—		18,292			*
Direct costs - general and administrative	27,482		51,085		(46	)%	102,858		108,501			(5	)%
Depreciation, depletion and amortization	56,070		98,692		(43	)%	220,176		311,404			(29	)%

*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.

- 12-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Definitions used throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations:

Bbl - One barrel of crude oil or NGLs or 42 gallons of liquid volume.

Boe - Barrels of crude oil equivalent.

Mcf - One thousand cubic feet of natural gas volume.

NGLs - Natural gas liquids

NYMEX - New York Mercantile Exchange

Crude Oil, Natural Gas, and NGLs Sales

Changes in Crude Oil, Natural Gas, and NGLs Production Volumes.  For the three and nine months ended September 30, 2017 as compared to the three and nine months ended September 30, 2016, crude oil, natural gas, and NGLs production, on a per barrel of oil equivalent ("Boe") basis, decreased 46 percent and 30 percent, respectively, primarily resulting from increasingly high line pressures on the gas gathering facilities, the natural decline rates of this Partnership's wells and fewer producing wells resulting from plugging and abandonment activity.

On a sequential quarterly basis, production for the third quarter 2017 declined to 9,200 Boe compared to 12,700 Boe for the second quarter and 16,000 Boe for the first quarter 2017. The main drivers in the decrease were a significant increase in the gathering system line pressures, the plugging abandonment activity and the natural decline rates of this Partnership's wells. Production throughout the remainder of 2017 is expected to be negatively impacted as line pressures are expected to increase due to the midstream provider currently processing at full capacity, along with the normal production decline in a well's production life cycle.

This Partnership’s production has historically been affected by extreme 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. Starting in late 2014 and into early 2015, field-wide line pressures increased significantly primarily due to the gathering systems being near capacity and increased ambient temperatures. This Partnership’s midstream service provider added additional compressors and a new processing plant in mid-2015, which lowered field-wide line pressures beginning in mid-2015 and continuing throughout the first half of 2016. Primarily as a result of the lowered system line pressures, this Partnership’s production remained the same in 2016 as compared to 2015, in spite of the natural decline in the well's life cycle.

During 2017, the line pressures on this Partnership's wells have sharply increased from an average of approximately 130 pounds per square inch (“psi”) at the beginning of the year to approximately 280 psi in September, an increase of 115 percent. This Partnership’s midstream service provider is currently processing at full capacity and basin-wide activity remains high; therefore, line pressures continue to be at high levels and may continue to increase.

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 psi. This Partnership's wells are approaching, and some are exceeding, the maximum limit now. 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 a commitment signed in December 2016 with the midstream provider to build additional gathering and processing capacity in the field. This expansion of gathering, compression, and processing facilities is expected to increase the capacity of the natural gas gathering pipelines and processing facilities in order to lower line pressures and accommodate more volumes in the field. However, the new facilities are not scheduled to go on line until the fourth quarter of 2018. The Managing General Partner expects that line pressures will remain high until the new plant is placed in service, causing this Partnership's wells to experience challenging periods of operation that negatively impact production that 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. The timing and availability of adequate infrastructure is not within the Managing General Partner’s nor 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 three and nine months ended September 30, 2017, as compared to the three and nine months ended September 30, 2016primarily 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 the White Cliffs pipeline as the purchasers do not provide transportation, gathering or processing. Under this method, this Partnership recognizes revenues based on the gross selling price. During the nine months ended September 30, 2017, this Partnership did not utilize the White Cliffs pipeline to transport a portion of its crude oil, and therefore did not incur any transportation, gathering, or processing expenses.

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.

Production Costs

Total production costs, which consist of lease operating expenses, production taxes, and transportation, gathering and processing 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.

Three months ended September 30, 2017 as compared to three months ended September 30, 2016

Total lease operating expenses for the three months ended September 30, 2017, decreased approximately $23,000 compared to the same period in 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 approximately $9,000 due to decreased crude oil and natural gas sales in the three months ended September 30, 2017 compared to the three months ended September 30, 2016 as noted above.

Nine months ended September 30, 2017 as compared to nine months ended September 30, 2016

Total lease operating expenses for the nine months ended September 30, 2017, decreased approximately$213,000 compared to the same period in 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. There was no change in production taxes as an eight percent decrease in crude oil, natural gas, and NGLs sales was offset by increased ad valorem tax effective rates in the nine months ended September 30, 2017 as compared to the same

- 13-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

period in 2016. Transportation, gathering and processing costs decreased by $18,000 as there was no crude oil delivered through the White Cliffs pipeline during the nine months ended September 30, 2017.

Direct costs - general and administrative

Three and nine months ended September 30, 2017 as compared to three and nine months ended September 30, 2016

Direct costs - general and administrative for the three months ended September 30, 2017 decreased approximately $24,000 compared to the same period in 2016 primarily due to lower audit and tax preparation fees. Similarly there was a decrease in the comparable nine month period ended September 30, 2017, as compared to the prior year, for the same reason.

Depreciation, Depletion and Amortization

Three months ended September 30, 2017 as compared to three months ended September 30, 2016

Depreciation, depletion, and amortization ("DD&A") expense decreased for the three months ended September 30, 2017, compared to the three months ended September 30, 2016, due to a 46 percent decrease in production. The DD&A expense rate per Boe increased slightly to$6.08 for the three months ended September 30, 2017 compared to $5.79 during the same period in 2016.

Nine months ended September 30, 2017 as compared to nine months ended September 30, 2016

Depreciation, depletion, and amortization ("DD&A") expense decreased for the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016, due to a 30 percentdecrease in production. The DD&A expense rate per Boe increased slightly to $5.81 for the nine months ended September 30,2017 as compared to $5.74 during the same period in 2016.

Asset Retirement Obligations and Accretion Expense

During the nine months ended September 30, 2017, this Partnership has plugged and abandoned 17 wells for a total estimated cost of approximately $860,000, which were offset by the release of the asset retirement obligations liability of approximately $945,000, resulting in a gain on settlement of asset retirement obligations of approximately $85,000.  Prior to 2017, this Partnership's plugging and abandonment activity had been limited; however, due to the increased plugging and abandonment activities during 2017, this Partnership's estimated future plugging and abandonment costs have been adjusted downward. See the footnote titled Asset Retirement Obligations for further details.

The current portion of the asset retirement obligations of $900,000 relates to 18 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 anticipated capital spending that would be required to meet newly-implemented environmental standards and the significantly increased high line pressure in the field. 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 has funded such activities. The Managing General Partner would recover amounts funded from future cash flows of this Partnership, if available.

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 previously owned by this Partnership in the Piceance Basin. This Partnership sold the wells in the Piceance Basin in 2013. 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.

- 14-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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 to 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 in compliance 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 nine months ended September 30, 2017 showed improvement relative to pricing experienced during the comparable period of 2016. However, this level of price improvement alone is not likely to be sufficient to alleviate concerns regarding this Partnership’s ability to meet its obligations. To meet such obligations, which total approximately$1.9 million at September 30, 2017, this Partnership would likely need to experience production volume improvement and/or commodity pricing would need to significantly improve over current levels.

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 gradual 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 which this Partnership is experiencing 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 at all, 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 September 30, 2017, this Partnership had a working capital deficit of $840,000, compared to working capital deficit of $886,000 at December 31, 2016. The $46,000 decrease in the working capital deficit from December 31, 2016 to September 30, 2017 was primarily due to:

•a $265,000 increase in cash; and

•a $308,000 decrease in the current portion of asset retirement obligations.

Partially offset by:

•a $406,000 increase in the amount due to the Managing General Partner; and

•a $140,000 decrease in accounts receivable.    

- 15-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Net cash from operating activities was $268,000 for the nine months ended September 30,2017, compared to net cash from operating activities of $234,000 for the comparable period in 2016.

This Partnership's cash flows from operating activities in the nine months ended September 30,2017 were primarily impacted by commodity prices, production volumes, operating costs, direct costs-general and administrative expenses, 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, proceeds received from the sale of crude oil and natural gas properties, and proceeds from the recovery of the sales tax refund. From time to time, this Partnership invests in equipment which supports treatment, delivery and measurement of crude oil, natural gas, and NGLs or environmental protection. During the nine months ended September 30, 2017, this Partnership investment in equipment was $47,000 compared to $46,000 for the nine months ended September 30, 2016. During the nine months ended September 30, 2017, this Partnership's proceeds from the sale of equipment salvaged from wells that were plugged and abandoned in 2017 were approximately $15,000 compared to no proceeds from sales in 2016. During the nine months ended September 30, 2017 this Partnership also received a sales tax refund of approximately $39,000.

Financing Activities

Cash flows from financing activities generally consist of cash distributions to investors. During the nine months ended September 30, 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 September 30, 2017, this Partnership had no off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on this Partnership's financial condition, results of operations, liquidity, capital expenditures, or capital resources.

Commitments and Contingencies

See the footnote titled Commitments and Contingencies, to the accompanying condensed financial statements included elsewhere in this report.

Recent Accounting Standards

See the footnote titled Summary of Significant Accounting Policies, to the accompanying condensed financial statements included elsewhere in this report.

- 16-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Recent Regulatory Developments

On May 2, 2017, in response to an incident in Firestone, Colorado, the Colorado Oil & Gas Conservation Commission (“COGCC”) issued a Notice to Operators (the “Notice”). Among other things, the Notice included requirements for all operators of oil and gas wells in Colorado to inspect all existing flowlines and pipelines located within 1,000 feet of a building unit; inspect any abandoned flowlines or pipelines, regardless of distance to ensure proper abandonment; and test integrity of all connected flowlines.

The Managing General Partner timely complied with both phases of the Notice. The Managing General Partner has an existing Flowline Integrity Management Program to inspect all DJ Basin wells and related pipelines on an annual basis, and will continue to engage in this process.

On August 22, 2017, the State announced its response to the incident, following a three month review of oil and gas operations. The policy initiatives proposed could come either through rulemaking or legislation.

Critical Accounting Policies and Estimates

The preparation of the accompanying condensed financial statements in conformity with U.S. GAAP requires management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities, and the reported amounts of revenue and expenses.

There have been no significant changes to this Partnership's critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in this Partnership's 2016 Form 10-K.

- 17-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. 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 September 30, 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 Principal 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).

Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and Principal Financial Officer concluded that this Partnership's disclosure controls and procedures were effective as of September 30, 2017.

(b)    Changes in Internal Control over Financial Reporting

During the three months ended September 30, 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.

- 18-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1.Legal Proceedings

From time to time, the Partnership is a party to various legal proceedings in the ordinary course of business. The Partnership is not currently a party to any litigation that the Managing General Partner believes would have a materially adverse effect on this Partnership's business, financial condition, results of operations, or liquidity.

Environmental

Due to the nature of the natural gas and oil industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures to minimize and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in environmental risks. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, the Managing General Partner is not aware of any environmental claims existing as of September 30, 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 past non-compliance with environmental laws will not be discovered on the Partnership's properties.

Clean Air Act Tentative 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") of Colorado. 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 the facilities. The Managing General Partner responded with the requested data to the Information Request 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 (“CDPHE”) 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.

For more than a year, the Managing General Partner held a series of meetings with the EPA, Department of Justice (“DOJ”) and CDPHE on the above matters. On June 26, 2017, the DOJ on behalf of the EPA, and the State of Colorado filed a complaint against PDC based on the above matters.

A consent decree resolving the matter was signed by all parties on October 31, 2017 and is subject to a 30-day comment period, which will be publicly published in the Federal Register. The consent decree provides that the Managing General Partner will implement changes to the design, operation, and maintenance of most of its field-wide storage tank systems to enhance the emission management in the DJ Basin.  Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors.  The three primary elements of the tentative settlement 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 cost associated with supplemental environmental projects. This Partnership will share proportionally in the injunctive relief and may share in the mitigation efforts required by the consent decree. The consent decree includes substantially all of this Partnership’s wells located across 26 production facilities. The profitability of older low-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 decisions to plug additional wells owned by this Partnership.

- 19-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 1A. Risk Factors

Not applicable.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

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 September 30, 2017.

Item 3.    Defaults Upon Senior Securities

Not applicable.

Item 4.    Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

None.

- 20-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6.    Exhibits Index

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
31.1	Certification of Chief Executive Officer of PDC Energy, Inc., the Managing General Partner of this Partnership, pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
31.2	Certification of Chief Financial Officer of PDC Energy, Inc., the Managing General Partner of this Partnership, pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
32.1*	Certifications of Chief Executive Officer and Chief Financial Officer of PDC Energy, Inc., the Managing General Partner of this Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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

*Furnished herewith.

- 21-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Barton R. Brookman

President and Chief Executive Officer

of PDC Energy, Inc.

November 13, 2017

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

Signature	Title	Date
/s/ Barton R. Brookman	President and Chief Executive Officer	November 13, 2017
Barton R. Brookman	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal executive officer)
/s/ David W. Honeyfield	Senior Vice President and Chief Financial Officer	November 13, 2017
David W. Honeyfield	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal financial officer)

- 22-

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Barton R. Brookman, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Rockies Region 2007 Limited Partnership;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 13, 2017
	/s/ Barton R. Brookman
	Barton R. Brookman
	Chief Executive Officer
	PDC Energy, Inc.
	Managing General Partner

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, David W. Honeyfield, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Rockies Region 2007 Limited Partnership;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 13, 2017
	/s/ David W. Honeyfield
	David W. Honeyfield
	Senior Vice President and Chief Financial Officer
	PDC Energy, Inc.
	Managing General Partner

EX-32.1

Exhibit 32.1

CERTIFICATION

FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES OXLEY ACT OF 2002

In connection with the Quarterly Report of Rockies Region 2007 Limited Partnership (the “Registrant”) on Form 10-Q for the period ended September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned certify pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Barton R. Brookman	November 13, 2017
Barton R. Brookman
President and Chief Executive Officer
PDC Energy, Inc.
Managing General Partner
/s/ David W. Honeyfield	November 13, 2017
David W. Honeyfield
Senior Vice President and Chief Financial Officer
PDC Energy, Inc.
Managing General Partner

XML

Document Entity Information Document	9 Months Ended
	Sep. 30, 2017 shares
Entity Information
Entity Registrant Name	ROCKIES REGION 2007 LP
Entity Central Index Key	0001407805
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	0.00
Additional General Partnership Units Outstanding	0

XML

Condensed Balance Sheets (Unaudited) Statement - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 841,004	$ 576,132
Accounts receivable	156,913	296,635
Crude oil inventory	33,960	14,453
Total current assets	1,031,877	887,220
Crude oil and natural gas properties, successful efforts method, at cost	4,152,109	4,355,731
Less: Accumulated depreciation, depletion and amortization	(2,520,363)	(2,300,187)
Crude oil and natural gas properties, net	1,631,746	2,055,544
Total Assets	2,663,623	2,942,764
Current liabilities:
Due to Managing General Partner-other, net	971,670	565,842
Current portion of asset retirement obligations	900,000	1,207,500
Total current liabilities	1,871,670	1,773,342
Asset retirement obligations	1,049,602	1,701,009
Total liabilities	2,921,272	3,474,351
Commitments and contingent liabilities
Partners' equity (deficit):
Managing General Partner	(5,285,706)	(5,390,635)
Limited Partners - 4,470 units issued and outstanding	5,028,057	4,859,048
Total Partners' equity (deficit)	(257,649)	(531,587)
Total Liabilities and Partners' Equity (Deficit)	$ 2,663,623	$ 2,942,764

XML

Balance Sheet Parentheticals (Parentheticals) - shares	Sep. 30, 2017	Dec. 31, 2016
Balance Sheet Parentheticals [Abstract]
Limited Partners' Capital Account, Units Issued	4,470	4,470
Limited Partners' Capital Account, Units Outstanding	4,470	4,470

XML

Condensed Statements of Operations (Unaudited) Statement - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues:
Crude oil, natural gas, and NGLs sales	$ 226,545	$ 448,702	$ 1,035,108	$ 1,128,862
Operating costs and expenses:
Lease operating expenses	149,123	172,110	482,984	695,678
Production taxes	7,606	16,451	41,993	41,742
Transportation, gathering and processing expenses	0	0	0	18,292
Direct costs - general and administrative	27,482	51,085	102,858	108,501
Depreciation, depletion, and amortization	56,070	98,692	220,176	311,404
Accretion of asset retirement obligations	35,055	48,750	150,390	143,329
Gain on recovery of sales tax refund	(121,348)	0	(121,348)	0
Gain on settlement of asset retirement obligations	(84,850)	0	(84,850)	0
Total operating costs and expenses	69,138	387,088	792,203	1,318,946
Income (loss) from operations	157,407	61,614	242,905	(190,084)
Interest income on sales tax refund	40,687	0	40,687	0
Operating Income (Loss)
Net income (loss)	198,094	61,614	283,592	(190,084)
Less: Managing General Partner interest in net income (loss)	73,295	(22,797)	104,929	(70,331)
Net Income (Loss) Allocated to Investor Partners	$ 124,799	$ 38,817	$ 178,663	$ (119,753)
Net income (loss) per Investor Partner units:
Net loss per Investor Partner unit	$ 27.92	$ 8.68	$ 39.97	$ (26.79)
Investor Partner units outstanding	4,470	4,470	4,470	4,470

XML

Condensed Statement of Partner's Equity (Unaudited) Statement - USD ($)	Total	Investor Partners	Managing General Partner
Limited Partners' Capital Account	$ 4,859,048	$ 4,859,048
Partners' Capital	(531,587)
General Partners' Capital Account	(5,390,635)		$ (5,390,635)
Distributions on behalf of Investor Partners for withholding taxes	(9,654)	(9,654)	0
Net income	283,592	178,663	104,929
Limited Partners' Capital Account	5,028,057	$ 5,028,057
Partners' Capital	(257,649)
General Partners' Capital Account	$ (5,285,706)		$ (5,285,706)

XML

Condensed Statements of Cash Flows (Unaudited) Statement - USD ($)	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities:
Net income (loss)	$ 283,592	$ (190,084)
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	220,176	311,404
Accretion of asset retirement obligations	150,390	143,329
Gain on settlement of asset retirement obligations	(84,850)	0
Gain on recovery of sales tax refund	(121,348)	0
Changes in assets and liabilities:
Accounts receivable	139,722	(45,949)
Crude oil inventory	(19,507)	21,247
Asset Retirement Obligation	(860,455)	0
Due from Managing General Partner-other, net	560,039	(5,845)
Net cash from operating activities	267,759	234,102
Cash Flows from Investing Activities:
Capital expenditures for crude oil and natural gas properties	(47,229)	(46,029)
Proceeds from Sale of Property, Plant, and Equipment	14,797	0
Gain on recovery of sales tax refund	39,199	0
Net cash from investing activities	6,767	(46,029)
Cash flows from financing activities:
Distributions on behalf of Investor Partners for withholding taxes	(9,654)	(3,621)
Distributions to Partners	0	(212,112)
Net cash from financing activities	(9,654)	(215,733)
Net change in cash and cash equivalents	264,872	(27,660)
Cash and cash equivalents, beginning of period	576,132	495,945
Cash and cash equivalents, end of period	841,004	468,285
Increase (Decrease) in Asset Retirement Obligations	(163,992)	0
Capital Expenditures Incurred but Not yet Paid	$ 32,863	0
Gain (Loss) on Sale of Properties, Net of Applicable Income Taxes		$ 0

XML

General and Basis of Presentation

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

General and Basis of Presentation

Rockies Region 2007 Limited Partnership (this “Partnership” or the “Registrant”) 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 Drilling and Operating Agreement (“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 Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of this Partnership and initiates and completes substantially all Partnership transactions.

As of September 30, 2017, there were 1,756 limited partners ("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. Due to the suspension of cash distributions during the first quarter of 2017, there is no value upon which to base the calculation, and therefore, no repurchase offers are currently being considered. On a cumulative basis, through September 30, 2017, the Managing General Partner has repurchased 153 units of Partnership interest from the Investor Partners at an average price of $2,258 per unit. As of September 30, 2017, the Managing General Partner owned approximately 39 percent of this Partnership, including the repurchased units. The Managing General Partner made no limited partner unit repurchases during the three months ended September 30, 2017.

In the Managing General Partner's opinion, the accompanying condensed financial statements contain all adjustments consisting of only normal recurring adjustments necessary for a fair statement of this Partnership's results for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 8 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The December 31, 2016, condensed balance sheet data was derived from this Partnership's audited financial statements, but does not include disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with this Partnership's audited financial statements and notes thereto included in this Partnership's 2016 Form 10-K. This Partnership's accounting policies are described in the Notes to Financial Statements in this Partnership's 2016 Form 10-K and updated, as necessary, in this Quarterly Report on Form 10-Q. The results of operations and cash flows for the nine months ended September 30, 2017, are not necessarily indicative of the results to be expected for the full year or any future period.

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.

XML

Going Concern Going Concern (Notes)

9 Months Ended

Sep. 30, 2017

Substantial Doubt about Going Concern [Text Block]

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. While this Partnership generated positive cash from operations for the nine months ended September 30, 2017, this Partnership had working capital deficits of $840,000 and $886,000 as of September 30, 2017 and December 31, 2016, respectively. The negative impact to its cumulative lack of liquidity resulting from sustained depressed commodity prices, the negative impact of high line pressures on the productivity and decreasing production from natural declines of the wells in this Partnership 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 is expected to amount to meaningful expenditures, 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 reimbursements of 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 Investor Partners' tax withholding requirements, is expected to remain in place until such time, if at all, 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.

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. Historically, as a result of the normal production decline in a well's production life cycle, this Partnership has not experienced a sustained increase in production without 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.

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.

XML

Recent Accounting Standards

9 Months Ended

Sep. 30, 2017

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Description of New Accounting Pronouncements Adopted [Text Block]

Summary of Significant Accounting Policies

Recently Issued Accounting Standards    

In May 2014, the Financial Accounting Standards Board ("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; we are 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 consolidated financial statements, the Managing General Partner is performing a comprehensive review of this Partnership's significant revenue streams. The focus of this review includes, among other things, the identification of the significant contracts and other arrangements this Partnership have with its customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of transaction price. The Managing General Partner is also reviewing 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 this Partnership will adopt the standard under the modified retrospective method. The Managing General Partner has not made a complete determination regarding the impact that the adoption will have on this Partnership's consolidated financial statements as of the time of this filing.

XML

Fair Value Measurements and Disclosures

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Fair Value Measurements

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

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. 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.

XML

Asset Retirement Obligations Asset Retirement Obligations (Notes)

9 Months Ended

Sep. 30, 2017

ASSET RETIREMENT OBLIGATIONS [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

Asset Retirement Obligations

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

	Amount
Balance at December 31, 2016	$	2,908,509
Revisions in estimated cash flows	(163,992		)
Obligations discharged with asset retirements and expenditures	(860,455		)
Accretion expense	150,390
Gain on settlement of asset retirement obligations	(84,850		)
Balance at September 30, 2017	1,949,602
Less current portion	(900,000		)
Long-term portion	$	1,049,602

This Partnership's estimated asset retirement obligations liability is based on the Managing General Partner's historical experience in plugging and abandoning this Partnership's wells, estimated economic lives and estimated plugging and abandonment costs considering federal and state regulatory requirements in effect. Prior to 2017, this Partnership's plugging and abandonment activity had been limited; however, during the nine months ended September 30, 2017, this Partnership plugged 17 wells. Based on the 2017 plugging and abandonment activities, this Partnership's estimated future plugging and abandonment costs have been adjusted downward by approximately $164,000 as reflected in the table above. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. As of September 30, 2017, the credit-adjusted risk-free rates used to discount this Partnership's plugging and abandonment liabilities ranged from 6.5 percent to 8.2 percent. In periods subsequent to initial measurement of the liability, this Partnership must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors and changes to this Partnership's credit-adjusted risk-free rate as market conditions warrant.

During the three and nine months ended September 30, 2017, this Partnership plugged and abandoned 17 wells for a total estimated cost of approximately $860,000. These costs were offset by the release of the asset retirement obligations liability of approximately $945,000, resulting in a gain on settlement of asset retirement obligations of approximately $85,000.  The current portion of the asset retirement obligations relates to 18 wells that are expected to be plugged and abandoned during the next 12 months.

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the oil and 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 September 30, 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 Tentative 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") of Colorado. 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 the facilities. The Managing General Partner responded with the requested data to the Information Request 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 (“CDPHE”) 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.

For more than a year, the Managing General Partner held a series of meetings with the EPA, Department of Justice (“DOJ”) and CDPHE on the above matters. On June 26, 2017, the DOJ on behalf of the EPA, and the State of Colorado filed a complaint against PDC based on the above matters.

A consent decree resolving the matter was signed by all parties on October 31, 2017 and is subject to a 30-day comment period, which will be publicly published in the Federal Register. The consent decree provides that the Managing General Partner will implement changes to the design, operation, and maintenance of most of its field-wide storage tank systems to enhance the emission management in the DJ Basin.  Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors.  The three primary elements of the tentative settlement 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 cost associated with supplemental environmental projects. This Partnership will share proportionally in the injunctive relief and may share in the mitigation efforts required by the consent decree. The consent decree includes substantially all of this Partnership’s wells located across 26 production facilities. The profitability of older low-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 decisions to plug additional wells owned by this Partnership.

XML

Transactions with Managing General Partner

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

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 $972,000 and $566,000 as of September 30, 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 on the condensed statements of operations. The fees for well operating and maintenance for the three and nine months ended September 30, 2017 were approximately $56,000 and $203,000, respectively. The fees for well operating and maintenance for the three and nine months ended September 30, 2016 were approximately $85,000 and $258,000, respectively. The decrease in fees in during three and nine months ended September 30, 2017 periods compared to 2016 is due to a decrease in the number of wells for which this Partnership is charged the fee.

XML

Sales Tax Refund (Notes)

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Text Block]

Sales Tax Refund

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 relates to a portion of this Partnership’s wells in the Wattenberg Field and $152,000 is related to wells previously owned by this Partnership in the Piceance Basin. This Partnership sold the wells in the Piceance Basin in 2013. 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 to the income statement as gain on recovery of sales tax refund and $31,000 was recorded as interest income.

XML

Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting, Policy [Policy Text Block]

In the Managing General Partner's opinion, the accompanying condensed financial statements contain all adjustments consisting of only normal recurring adjustments necessary for a fair statement of this Partnership's results for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 8 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The December 31, 2016, condensed balance sheet data was derived from this Partnership's audited financial statements, but does not include disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with this Partnership's audited financial statements and notes thereto included in this Partnership's 2016 Form 10-K. This Partnership's accounting policies are described in the Notes to Financial Statements in this Partnership's 2016 Form 10-K and updated, as necessary, in this Quarterly Report on Form 10-Q. The results of operations and cash flows for the nine months ended September 30, 2017, are not necessarily indicative of the results to be expected for the full year or any future period.

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.

XML

Recent Accounting Standards Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Significant Accounting Policies [Abstract]

Recently Issued Accounting Standards [Text Block]

Recently Issued Accounting Standards    

In May 2014, the Financial Accounting Standards Board ("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; we are 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 consolidated financial statements, the Managing General Partner is performing a comprehensive review of this Partnership's significant revenue streams. The focus of this review includes, among other things, the identification of the significant contracts and other arrangements this Partnership have with its customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of transaction price. The Managing General Partner is also reviewing 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 this Partnership will adopt the standard under the modified retrospective method. The Managing General Partner has not made a complete determination regarding the impact that the adoption will have on this Partnership's consolidated financial statements as of the time of this filing.

XML

Asset Retirement Obligations Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2017

ASSET RETIREMENT OBLIGATIONS [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

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

	Amount
Balance at December 31, 2016	$	2,908,509
Revisions in estimated cash flows	(163,992		)
Obligations discharged with asset retirements and expenditures	(860,455		)
Accretion expense	150,390
Gain on settlement of asset retirement obligations	(84,850		)
Balance at September 30, 2017	1,949,602
Less current portion	(900,000		)
Long-term portion	$	1,049,602

XML

Transactions with Managing General Partner Transactions with Managing General Partner (Tables)

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Due from (to) Managing General Partner-other, net [Table Text Block]

This Partnership's net amount due to the Managing General Partner was approximately $972,000 and $566,000 as of September 30, 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.

Schedule of Related Party Transactions [Table Text Block]

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 on the condensed statements of operations. The fees for well operating and maintenance for the three and nine months ended September 30, 2017 were approximately $56,000 and $203,000, respectively. The fees for well operating and maintenance for the three and nine months ended September 30, 2016 were approximately $85,000 and $258,000, respectively. The decrease in fees in during three and nine months ended September 30, 2017 periods compared to 2016 is due to a decrease in the number of wells for which this Partnership is charged the fee.

XML

General and Basis of Presentation General and Basis of Presentation (Details)	9 Months Ended
	Sep. 30, 2017 Number_of_Limited_Partners $ / shares shares
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Investor Partners | Number_of_Limited_Partners	1,756
Managing General Partner, Ownership Interest Before Unit Repurchases	37.00%
Investor Partner Ownership Interest	63.00%
Limited Partner Units Repurchased by Managing General Partner | shares	153
Average Price Paid for Units Repurchased by Managing General Partner | $ / shares	$ 2,258
Managing General Partner Ownership Interest	39.00%

XML

Going Concern Going Concern (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Going Concern [Abstract]
working capital	$ (840,000)	$ (886,000)

XML

Asset Retirement Obligations Asset Retirement Obligations (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($) Wells	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) Wells	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)
Changes in carrying amounts of Asset Retirement Obligation [Line Items]
Oil and Gas Wells Plugged			17
Asset Retirement Obligation, Liabilities Settled			$ 945,000
Asset Retirement Obligation, Revision of Estimate			(163,992)
Asset Retirement Obligation			(860,455)	$ 0
Changes in asset retirement obligations
Balance at December 31, 2016			2,908,509
Accretion Expense	$ 35,055	$ 48,750	150,390	143,329
Balance at March 31, 2017	1,949,602		1,949,602
Less current portion	(900,000)		(900,000)		$ (1,207,500)
Long-term portion	1,049,602		1,049,602		$ 1,701,009
Gain on settlement of asset retirement obligations	$ (84,850)	$ 0	$ (84,850)	$ 0
Minimum [Member]
Changes in carrying amounts of Asset Retirement Obligation [Line Items]
OIl and Gas Wells Expected to be Plugged | Wells	18		18

XML

Transactions with Managing General Partner Undistributed or Unsettled Transactions With Investor Partners (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Related Party Transaction
Due to Managing General Partner-other, net	$ 971,670	$ 565,842

XML

Transactions with Managing General Partner Related Party Transactions (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Transactions with Managing General Partner
Related Party Transaction
Well operations and maintenance	$ 55,783	$ 85,203	$ 203,347	$ 258,454

XML

Sales Tax Refund (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Taxes, Miscellaneous	$ 201,000
Gain on recovery of sales tax refund	(121,348)	$ 0	$ (121,348)	$ 0
Proceeds from Income Tax Refunds			39,199	0
Interest income on sales tax refund	40,687	$ 0	$ 40,687	$ 0
Wattenberg Field [Member]
Gain on recovery of sales tax refund	49,000
Interest income on sales tax refund	10,000
Piceance and NECO Asset Group [Member]
Gain on recovery of sales tax refund	152,000
Interest income on sales tax refund	$ 31,000