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, 2013

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 R No £

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

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

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

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

As of September 30, 2013 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)	2
	Condensed Statements of Operations (unaudited)	3
	Condensed Statements of Cash Flows (unaudited)	4
	Notes to Unaudited Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	20
Item 4.	Controls and Procedures	20
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	21
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	21
Item 3.	Defaults Upon Senior Securities	21
Item 4.	Mine Safety Disclosures	21
Item 5.	Other Information	21
Item 6.	Exhibits	22
	SIGNATURES	23

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 United States ("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: estimated crude oil, natural gas and natural gas liquids ("NGLs") reserves; future production (including the components of such production), sales, expenses, cash flows and liquidity; anticipated capital expenditures and projects; availability of additional midstream facilities and services, timing of that availability and related benefits to this Partnership; the impact of high line pressures and the expected impact of the O'Connor (formerly known as LaSalle) gas plant; and the Managing General Partner's future strategies, plans and objectives.

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

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

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

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

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

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

• changes in estimates of proved reserves;

• inaccuracy of reserve estimates and expected production rates;

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

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

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

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

• timing and receipt of necessary regulatory permits;

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

• future cash flows, liquidity and financial condition;

• competition within the oil and gas industry;

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

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

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

• cost of pending or future litigation;

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

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

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

Further, this Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this Quarterly Report on Form 10-Q, this Partnership's Annual Report on Form 10-K for the year ended December 31, 2012 (the “2012 Form 10-K”) filed with the U.S. Securities and Exchange Commission (“SEC”) on March 27, 2013 and this Partnership's other filings with the SEC for further information on risks and uncertainties that could affect this Partnership's business, financial condition, results of operations and cash flows. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. This Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement.

- 1-

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

Rockies Region 2007 Limited Partnership

Condensed Balance Sheets

(unaudited)

	September 30, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	570,376		$	570,376
Accounts receivable	467,987			865,944
Crude oil inventory	49,053			42,939
Due from Managing General Partner-derivatives	—			4,409,574
Due from Managing General Partner-other, net	54,030			800,598
Total current assets	1,141,446			6,689,431
Crude oil and natural gas properties, successful efforts method, at cost	55,758,995			79,601,649
Less: Accumulated depreciation, depletion and amortization	(31,136,270		)	(38,868,788		)
Crude oil and natural gas properties, net	24,622,725			40,732,861
Other assets	79,377			46,711
Total Assets	$	25,843,548		$	47,469,003
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	42,045		$	90,570
Due to Managing General Partner-derivatives	—			2,004,594
Total current liabilities	42,045			2,095,164
Asset retirement obligations	918,245			1,110,093
Total liabilities	960,290			3,205,257
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	4,012,858			11,183,638
Limited Partners - 4,470 units issued and outstanding	20,870,400			33,080,108
Total Partners' equity	24,883,258			44,263,746
Total Liabilities and Partners' Equity	$	25,843,548		$	47,469,003

See accompanying notes to unaudited condensed financial statements.

- 2-

Rockies Region 2007 Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended September 30,					Nine months ended September 30,
	2013		2012			2013			2012
Revenues:
Crude oil, natural gas and NGLs	$	1,500,286	$	1,784,184		$	4,536,215		$	4,261,718
Commodity price risk management gain (loss), net	—		(352,799		)	(417,689		)	751,177
Total revenues	1,500,286		1,431,385			4,118,526			5,012,895
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	331,242		281,879			980,150			992,892
Direct costs - general and administrative	42,575		42,510			129,317			124,625
Depreciation, depletion and amortization	761,369		926,048			2,438,069			2,505,337
Accretion of asset retirement obligations	17,229		15,941			50,699			46,911
Total operating costs and expenses	1,152,415		1,266,378			3,598,235			3,669,765
Income from continuing operations	347,871		165,007			520,291			1,343,130
Loss from discontinued operations	—		(293,406		)	(33,370		)	(967,091		)
Net income (loss)	$	347,871	$	(128,399	)	$	486,921		$	376,039
Income from continuing operations	$	347,871	$	165,007		$	520,291		$	1,343,130
Less: Managing General Partner interest in income from continuing operations	128,712		61,053			192,508			496,958
Income from continuing operations allocated to Investor Partners	$	219,159	$	103,954		$	327,783		$	846,172
Loss from discontinued operations	$	—	$	(293,406	)	$	(33,370	)	$	(967,091	)
Less: Managing General Partner interest in loss from discontinued operations	—		(108,560		)	(12,347		)	(357,824		)
Loss from discontinued operations allocated to Investor Partners	$	—	$	(184,846	)	$	(21,023	)	$	(609,267	)
Net income (loss) per Investor Partner unit
Continuing operations	$	49	$	23		$	73		$	189
Discontinued operations	—		(41		)	(4		)	(136		)
Net income (loss) per Investor Partner unit	$	49	$	(18	)	$	69		$	53
Investor Partner units outstanding	4,470.00		4,470.00			4,470.00			4,470.00

See accompanying notes to unaudited condensed financial statements.

- 3-

Rockies Region 2007 Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2013			2012
Cash flows from operating activities:
Net income	$	486,921		$	376,039
Adjustments to net income to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	2,593,279			3,843,085
Accretion of asset retirement obligations	57,576			58,618
Change in unrealized loss on derivative transactions	1,693,233			2,095,486
Loss on sale of crude oil and natural gas properties	495,574			—
Changes in assets and liabilities:
Accounts receivable	397,957			(77,131		)
Crude oil inventory	(11,028		)	(1,979		)
Other assets	(32,666		)	(32,673		)
Accounts payable and accrued expenses	(48,525		)	(7,507		)
Due from Managing General Partner-other, net	746,568			(360,759		)
Net cash from operating activities	6,378,889			5,893,179
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	—			(3,128,044		)
Proceeds from sale of crude oil and natural gas properties	13,488,520			—
Net cash from investing activities	13,488,520			(3,128,044		)
Cash flows from financing activities:
Distributions to Partners	(19,867,409		)	(4,306,135		)
Net cash from financing activities	(19,867,409		)	(4,306,135		)
Net change in cash and cash equivalents	—			(1,541,000		)
Cash and cash equivalents, beginning of period	570,376			2,690,377
Cash and cash equivalents, end of period	$	570,376		$	1,149,377

See accompanying notes to unaudited condensed financial statements.

- 4-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2013

(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, 2013, there were 1,784 limited partners in this Partnership (the “Investor Partners”). PDC is the designated Managing General Partner of this Partnership and owns a 37% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 63% to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership, and 37% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through September 30, 2013, the Managing General Partner had repurchased 39.3 units of Partnership interest from the Investor Partners at an average price of $4,233 per unit. As of September 30, 2013, the Managing General Partner owned 37.6% of this Partnership.

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 presentation 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 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 2012 Form 10-K. This Partnership's accounting policies are described in the Notes to Financial Statements in this Partnership's 2012 Form 10-K and updated, as necessary, in this Quarterly Report on Form 10-Q. The results of operations and cash flows for the three and nine months ended September 30,2013 are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications had no impact on previously reported results of operations, cash flows or Partners’ equity.

Note 2 - Summary of Significant Accounting Policies

Recently Adopted Accounting Standard

On January 1, 2013, this Partnership adopted changes issued by the Financial Accounting Standards Board regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of the entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. Adoption of these changes had no impact on the condensed financial statements.

- 5-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2013

(unaudited)

Note 3 - Transactions with Managing General Partner

The Managing General Partner transacts business on behalf of this Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received by the Managing General Partner on behalf of this Partnership are distributed to the Partners, net of corresponding operating costs and other cash outflows incurred on behalf of this Partnership. The fair value of this Partnership's portion of open derivative instruments were recorded on the condensed December 31, 2012 balance sheet under the captions “Due from Managing General Partner-derivatives” in the case of net unrealized gains and “Due to Managing General Partner-derivatives” in the case of net unrealized losses. As of September 30, 2013, this Partnership had no outstanding derivative instruments.

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

	September 30, 2013			December 31, 2012
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	463,071		$	871,548
Commodity price risk management, realized gain	—			356,531
Other (1)	(409,041		)	(427,481		)
Total Due from Managing General Partner-other, net	$	54,030		$	800,598

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

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner for the three and nine months ended September 30,2013 and 2012. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the condensed statements of operations for continuing operations or in Note 8, Divestitures and Discontinued Operations, for discontinued operations.    

	Three months ended September 30,					Nine months ended September 30,
	2013			2012		2013		2012
Well operations and maintenance	$	273,771		$	522,592	$	1,282,415	$	1,753,939
Gathering, compression and processing fees	(3,807		)	65,812		119,017		267,175
Direct costs - general and administrative	42,575			42,510		455,368		124,625
Refracturing and recompletion costs	—			2,766,186		—		3,126,425
Cash distributions (1)	5,694,280			509,856		7,445,561		1,599,789

(1) Cash distributions include $74,804 and $94,620 during the three and nine months ended September 30, 2013, respectively, and $4,099 and $6,519 during the three and nine months ended September 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC. The increases for 2013 periods over the 2012 periods is attributable to PDC's proportionate share of the distribution of $13.5 million received from the Piceance Basin asset divestiture in 2013.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2013

(unaudited)

Note 4 - Fair Value of Financial Instruments

Determination of fair value. This Partnership's fair value measurements are 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 three levels of inputs that may be used to measure fair value are defined as:

Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.

Derivative instruments that were due to mature subsequent to June 30, 2013 were either liquidated or sold to Caerus Oil and Gas LLC ("Caerus") during the quarter ended June 30, 2013. See Note 8, Divestitures and Discontinued Operations, for additional information regarding transactions with Caerus. Accordingly, as of September 30, 2013, this Partnership did not have any derivative instruments in place for its future production. When applicable, the Managing General Partner measured the fair value of this Partnership's derivative instruments based on a pricing model that utilized market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas forward curve, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validated its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While the Managing General Partner used common industry practices to develop its valuation techniques, and believed this Partnership's valuation method was appropriate and consistent with those used by other market participants, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values.

- 7-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2013

(unaudited)

This Partnership's fixed-price swaps and basis swaps as of December 31, 2012 were included in Level 2. The following table presents this Partnership's derivative assets and liabilities that had been measured at fair value on a recurring basis:

	Balance Sheet	December 31, 2012
	Line Item	Level 2
Assets:
Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	4,409,574
Total assets		4,409,574
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	2,004,594
Total liabilities		2,004,594
Net asset		$	2,404,980

Non-Derivative Financial Assets and Liabilities

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

Note 5 - Derivative Financial Instruments

The following tables present the impact of this Partnership's derivative instruments on this Partnership's accompanying condensed statements of operations:

	Three months ended September 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Gains (Losses) for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Gains and (Losses) for the Current Period			Total
Commodity price risk management loss, net
Realized gains	$	—		$	—		$	—		$	854,344		$	11,105		$	865,449
Unrealized losses	—			—			—			(854,344		)	(363,904		)	(1,218,248		)
Total	$	—		$	—		$	—		$	—		$	(352,799	)	$	(352,799	)
	Nine months ended September 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Losses for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Gains for the Current Period			Total
Commodity price risk management gain (loss), net
Realized gains (losses)	$	1,693,233		$	(417,689	)	$	1,275,544		$	2,264,797		$	581,866		$	2,846,663
Unrealized gains (losses)	(1,693,233		)	—			(1,693,233		)	(2,264,797		)	169,311			(2,095,486		)
Total	$	—		$	(417,689	)	$	(417,689	)	$	—		$	751,177		$	751,177

- 8-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2013

(unaudited)

Note 6 - Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the oil and gas industry, this Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in this Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews. Liabilities for environmental remediation efforts are included in line item captioned “Accounts payable and accrued expenses” on the condensed balance sheets.

During the nine months ended September 30, 2013, as a result of the Managing General Partner's periodic review, no new environmental remediation liabilities were identified and this Partnership's expense for environmental remediation efforts was not significant. This Partnership's environmental remediation liabilities were insignificant as of September 30, 2013 and December 31, 2012.

The Managing General Partner is not currently aware of any environmental claims existing as of September 30, 2013 which have not been provided for or would otherwise have a material impact on this Partnership's condensed financial statements; however, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on this Partnership's properties.

Royalty Matters

During the three months ended June 30, 2013, this Partnership recognized charges totaling approximately $326,000 related to royalty payment disputes with interest owners in the Piceance Basin. These charges were included in Direct costs - general and administrative expenses within discontinued operations. The settlement charges were allocated to this Partnership based upon historical revenue amounts and were paid during the three months ended September 30, 2013, thereby settling all current and future obligations related to this matter.

Note 7 - Asset Retirement Obligations

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

	Amount
Balance at December 31, 2012	$	1,110,093
Accretion expense	57,576
Obligations discharged with divestiture of properties	(249,424		)
Balance at September 30, 2013	$	918,245

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2013

(unaudited)

Note 8 - Divestitures and Discontinued Operations

Piceance Basin. In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement with certain affiliates of Caerus, pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $13.5 million, subject to customary post-closing adjustments. The divestiture of this Partnership's Piceance Basin assets resulted in a decrease of crude oil and natural gas properties of $23.8 million and a decrease of accumulated depreciation, depletion and amortization of $10.3 million. The sale resulted in a loss on divestiture of assets of approximately $0.5 million.

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture to the Managing General Partner and Investor Partners as follows:

	Amount
Distributed to:	(millions)
Managing General Partner	$	5.0
Investor Partners	8.5
Total	$	13.5

Following the sale, this Partnership does not have a significant continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the condensed statement of operations for all periods presented.

The following table presents statement of operations data related to this Partnership's discontinued operations for the Piceance Basin divestiture:

	Three Months Ended September 30,			Nine Months Ended September 30,
Statement of Operations - Discontinued Operations	2012			2013			2012
Revenues:
Crude oil, natural gas and NGLs sales	$	547,394		$	1,691,225		$	1,530,684
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	395,684			740,883			1,148,320
Depreciation, depletion and amortization	441,148			155,210			1,337,748
Direct costs - general and administrative expense	—			326,051			—
Accretion of asset retirement obligations	3,968			6,877			11,707
Loss on sale of crude oil and natural gas properties	—			495,574			—
Total operating costs and expenses	840,800			1,724,595			2,497,775
Loss from discontinued operations	$	(293,406	)	$	(33,370	)	$	(967,091	)

While the reclassification of revenues and expenses related to discontinued operations for the prior period had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.

- 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

Rockies Region 2007 Limited 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 operates 75 gross (73.9 net) productive wells located in the Wattenberg Field of Colorado. The Managing General Partner markets this Partnership's crude oil, natural gas and NGLs production to midstream marketers. Crude oil, natural gas and NGLs are sold primarily under market-sensitive 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 the monthly well operating charge. Seasonal factors, such as effects of weather on prices received, costs incurred and availability of PDC or third-party owned pipeline capacity, and other factors such as high pressures in the gathering system whether caused by heat or third-party facilities issues, may impact this Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Recent Developments

Crude Oil and Natural Gas Properties Divestiture

In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement with certain affiliates of Caerus, pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. This divestiture was completed in June 2013 with total consideration to this Partnership of $13.5 million, subject to customary post-closing adjustments. The sale resulted in a loss on divestiture of assets of $0.5 million. In July 2013, this Partnership distributed the proceeds of the sale to its partners on a pro rata basis. Following the sale to Caerus, this Partnership does not have continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the condensed statement of operations for all periods presented.

Partnership Operating Results Overview

Crude oil, natural gas and NGLs sales from continuing operations increased 6%, or $0.3 million, for the nine months ended September 30, 2013 compared to the same period of 2012, as sales volumes from continuing operations also increased 6% period-to-period. The increase in sales volumes was the result of increased production in 2013 from wells refractured or recompleted in accordance with the Additional Development Plan and turned-in-line during the nine months ended September 30, 2012. See this Partnership's 2012 Form 10-K for additional details on the Additional Development Plan. Production gains from refractured or recompleted wells were partially offset by the normal production declines.

The average sales price per barrel of crude oil equivalent ("Boe"), excluding the impact of realized derivative gains, was $52.34 for the current period compared to $52.35 for the same period a year ago. Realized gains from all natural gas derivatives, including net gains from the sale of this Partnership's remaining derivative positions in late June, contributed $1.3 million to total revenues for the nine months ended September 30, 2013, compared to $2.8 million from natural gas derivatives for the same period of 2012.

- 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 from continuing operations:

	Three months ended September 30,						Nine months ended September 30,
	2013		2012		Change		2013		2012		Change
Number of gross producing wells (end of period)	75		75		—		75		75		—
Production(1)
Crude oil (Bbl)	12,640		18,100		(30	)%	40,934		41,117		*
Natural gas (Mcf)	54,335		59,934		(9	)%	173,529		147,969		17	%
NGLs (Bbl)	5,369		6,346		(15	)%	16,812		15,626		8	%
Crude oil equivalent (Boe)(2)	27,065		34,435		(21	)%	86,667		81,404		6	%
Average Boe per day	294		374		(21	)%	317		297		6	%
Crude oil, natural gas and NGLs sales
Crude oil	$	1,240,866	$	1,557,777	(20	)%	$	3,713,744	$	3,657,802	2	%
Natural gas	162,979		143,042		14	%	550,662		316,874		74	%
NGLs	96,441		83,365		16	%	271,809		287,042		(5	)%
Total crude oil, natural gas and NGLs sales	$	1,500,286	$	1,784,184	(16	)%	$	4,536,215	$	4,261,718	6	%
Realized gain on derivatives, net
Natural gas	$	—	$	865,449	(100	)%	$	1,275,544	$	2,846,663	(55	)%
Total realized gain on derivatives, net	$	—	$	865,449	(100	)%	$	1,275,544	$	2,846,663	(55	)%
Average selling price (excluding realized gain on derivatives)
Crude oil (per Bbl)	$	98.17	$	86.07	14	%	$	90.73	$	88.96	2	%
Natural gas (Mcf)	3.00		2.39		26	%	3.17		2.14		48	%
NGLs (Bbl)	17.96		13.14		37	%	16.17		18.37		(12	)%
Crude oil equivalent (per Boe)	55.43		51.81		7	%	52.34		52.35		*
Average cost per Boe
Crude oil, natural gas and NGLs production cost(3)	$	12.24	$	8.19	49	%	$	11.31	$	12.20	(7	)%
Depreciation, depletion and amortization	28.13		26.89		5	%	28.13		30.78		(9	)%
Operating costs and expenses
Direct costs - general and administrative	$	42,575	$	42,510	*		$	129,317	$	124,625	4	%
Depreciation, depletion and amortization	761,369		926,048		(18	)%	2,438,069		2,505,337		(3	)%
Cash distributions	$	15,187,824	$	1,366,909	*		$	19,867,409	$	4,306,135	*

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

Amounts may not recalculate due to rounding.

_______________

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

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

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

- 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.

MBbl - One thousand barrels of crude oil or NGLs.

Mcf - One thousand cubic feet of natural gas volume.

MMBtu - One million British thermal units.

MMcf - One million cubic feet of natural gas volume.

Crude Oil, Natural Gas and NGLs Sales

In recent periods, this Partnership's Wattenberg Field production has been adversely impacted by high line pressures on the gathering system operated by the Managing General Partner's third-party service provider. Ongoing industry drilling activity in the area has resulted in increased volumes on the gathering system with associated increased system pressures. In addition, higher temperatures resulted in reduced system compressor efficiencies and further increased line pressures in the summer months. The curtailments that have occurred to date in 2013 are consistent with what the Managing General Partner expected at the beginning of the year. The Managing General Partner, and other operators in the field, are working closely with this Partnership's primary midstream provider in the Wattenberg Field, who is implementing a multi-year facility expansion program. This expansion will significantly increase the long-term gathering and processing capacity of the system. Initial system improvements have already been implemented with the startup of new field compressor stations, as well as installation and commissioning of gas bypass facilities at two gas processing plants in May and June of 2013. These projects increased midstream system capacity and have helped to mitigate the impact of increased production volumes on system pressures. In addition, the new O’Connor (formerly known as LaSalle) gas plant commenced operations on October 8, 2013 and will be further expanded in early 2014 to accommodate additional system volumes. Like most producers, this Partnership relies on third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with production growth. As a result, the timing and availability of additional facilities going forward is beyond this Partnership's or the Managing General Partner's control.

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. These price variations can have a material impact on this Partnership's financial results and capital expenditures.

Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics. The majority of this Partnership's crude oil is sold on a calendar-year basis at a fixed differential to NYMEX pricing. Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price this Partnership receives for its natural gas produced is based on the Colorado Interstate Gas ("CIG") price. This Partnership's NGLs price is mainly based on prices from the Conway hub in Kansas where the Wattenberg production is marketed.

This Partnership currently uses the "net-back" method of accounting for these arrangements related to its commodity sales. This Partnership sells commodities at the wellhead and collects a price and recognizes revenues based on the wellhead sales price as transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

- 13-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Nine months ended September 30, 2013 as compared to nine months ended September 30, 2012

For the nine months ended September 30, 2013 compared to the same period of 2012, crude oil, natural gas and NGLs production from continuing operations, on an energy equivalency-basis, increased 6%, primarily due to increased production from wells refractured or recompleted in accordance with the Additional Development Plan and turned-in-line during the nine months ended September 30, 2012. The benefits realized from refractured or recompleted wells were partially offset normal production declines for this stage in the wells’ production life cycle.

The approximate $274,000, or 6%, increase in sales from continuing operations for the 2013nine month period as compared to the prior year period was a reflection of sales volume increases of 6%. The average sales price per Boe, excluding the impact of realized derivative gains, was $52.34 for the current year nine month period compared to $52.35 for the same period a year ago.

Crude oil and natural gas sales from continuing operations for the nine months ended September 30, 2013 increased by 2% and 74%, respectively, partially offset by decreased NGLs sales of 5% as compared to the nine months ended September 30, 2012. The crude oil sales increase was due primarily to an averaging sales price increase of 2%. The increase in natural gas sales resulted from increased prices per Mcf of 48% and by higher natural gas production volumes of 17%. The increase in natural gas price per Mcf for the nine months ended September 30, 2013 was the result of higher market prices. The decrease in NGLs sales was due to a decrease of 12% in the average sales price, partially offset by an 8% increase in NGLs production volumes.

Three months ended September 30, 2013 as compared to three months ended September 30, 2012

For the three months ended September 30, 2013 compared to the same period of 2012, crude oil, natural gas and NGLs production from continuing operations, on an energy equivalency-basis, decreased 21%, primarily due to normal production declines for this stage in the wells’ production life cycle.

The approximate $284,000, or 16%, decrease in sales from continuing operations for the 2013 three month period as compared to the prior year period was a reflection of sales volume decreases of 21%, partially offset by an increase in the average sales price of 7%. The average sales price per Boe, excluding the impact of realized derivative gains, was $55.43 for the current year three month period compared to $51.81 for the same period a year ago.

Natural gas and NGLs sales from continuing operations for the three months ended September 30, 2013 increased by 14% and 16%, respectively, partially offset by decreased by crude oil sales of 20% as compared to the three months ended September 30, 2012. The increase in the natural gas sales in the 2013 period relative to the 2012 period was due to an increase in the price per Mcf of 26%, partially offset by lower natural gas production volumes of 9%. The increase in NGLs sales was due to an increase in the average commodity price per Bbl of 37%, partially offset by a 15% decrease in NGLs production volumes. The decrease in crude oil sales was due primarily to a sales volume decrease of 30%, partially offset by an increase in the average commodity price per Bbl of 14%.

Commodity Price Risk Management

This Partnership used various derivative instruments to manage fluctuations in natural gas prices. In June 2013, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated or sold to Caerus. Accordingly, as of September 30, 2013, this Partnership did not have any derivative instruments in place for its future production. Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production.

This Partnership had in place collars, fixed-price swaps and/or basis swaps on a portion of this Partnership's estimated natural gas production. This Partnership sold its natural gas at similar prices to the indices inherent in this Partnership's derivative instruments. As a result, for the volumes underlying this Partnership's derivative positions, this Partnership ultimately realized a price related to its collars of no less than the floor and no more than the ceiling and, for this Partnership's commodity swaps, this Partnership ultimately realized the fixed price related to its swaps.

Commodity price risk management includes realized gains and losses and unrealized mark-to-market changes in the fair value of the derivative instruments related to this Partnership's natural gas production. See Note 4, Fair Value of Financial Instruments, and Note 5, Derivative Financial Instruments, to this Partnership's condensed financial statements included elsewhere in this report for additional details of this Partnership's derivative financial instruments.

- 14-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management gain (loss), net:

	Three months ended September 30,				Nine months ended September 30,
		2012			2013			2012
Commodity price risk management gain (loss), net:
Realized gains
Natural gas		$	865,449		$	1,275,544		$	2,846,663
Total realized gains, net		865,449			1,275,544			2,846,663
Unrealized gains (losses)
Reclassification of realized gains included in
prior periods unrealized gains		(854,344		)	(1,693,233		)	(2,264,797		)
Unrealized gains (losses) for the period		(363,904		)	—			169,311
Total unrealized losses, net		(1,218,248		)	(1,693,233		)	(2,095,486		)
Total commodity price risk management gain (loss), net		$	(352,799	)	$	(417,689	)	$	751,177

Nine months ended September 30, 2013 as compared to nine months ended September 30, 2012

This Partnership had no crude oil, natural gas or NGLs derivative activity subsequent to June 30, 2013 as all open positions were either sold or liquidated prior to June 30, 2013. Realized gains of approximately $1.3 million recognized in the nine months ended September 30, 2013 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the nine months ended September 30, 2013, realized gains on natural gas, exclusive of basis swaps, were $2.5 million. These gains were offset in part by realized losses of $1.2 million on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average prices was narrower than the strike price of this Partnership's basis swaps.

Realized gains of $2.8 million recognized in the nine months ended September 30, 2012 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the nine months ended September 30, 2012, realized gains on natural gas, exclusive of basis swaps, were $4.6 million. These gains were offset in part by realized losses of $1.8 million on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average prices was narrower than the strike price of this Partnership's basis swaps.

Unrealized gains of $0.2 million for the nine months ended September 30, 2012 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of this Partnership's open positions, offset in part by the narrowing of the CIG basis forward curve. For the nine-month period ended September 30, 2012, unrealized gains on this Partnership's natural gas positions were $0.3 million, partially offset by unrealized losses on this Partnership's CIG basis swaps of $0.1 million.

Three months ended September 30, 2013 as compared to three months ended September 30, 2012

This Partnership had no crude oil, natural gas or NGLs derivative activity during the three months ended September 30, 2013 as all open positions were either sold or liquidated prior to June 30, 2013.

Realized gains of $0.9 million recognized in the three months ended September 30, 2012 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the three months ended September 30, 2012, realized gains on natural gas, exclusive of basis swaps, were $1.4 million. These gains were offset in part by realized losses of $0.5 million on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average prices was narrower than the strike price of this Partnership's basis swaps.

Unrealized losses of $0.4 million for the three months ended September 30, 2012 were primarily related to the upward shift in the natural gas forward curve and its impact on the fair value of this Partnership's open positions and by unrealized losses on CIG basis protection swaps due to the narrowing of the CIG basis forward curve.

- 15-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Crude Oil, Natural Gas and NGLs Production Costs

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

Nine months ended September 30, 2013 as compared to nine months ended September 30, 2012

Crude oil, natural gas and NGLs production costs for the nine months ended September 30, 2013 decreased approximately $13,000 compared to the same period in 2012 as a result of decreased workover activities in 2013. Crude oil, natural gas and NGLs production costs per Boe decreased to $11.31 during 2013 from $12.20 in 2012 due to higher volumes and decreased operating costs.

Three months ended September 30, 2013 as compared to three months ended September 30, 2012

Crude oil, natural gas and NGLs production costs for the three months ended September 30, 2013 increased approximately $49,000 compared to the same period in 2012 as a result of increased workover activities in 2013. Crude oil, natural gas and NGLs production costs per Boe increased to $12.24 during 2013 from $8.19 in 2012 due to lower volumes and higher operating costs.

Depreciation, Depletion and Amortization

Nine months ended September 30, 2013 as compared to nine months ended September 30, 2012

Depreciation, depletion and amortization ("DD&A") expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense for continuing operations decreased approximately $67,000 for the nine months ended September 30, 2013 compared to the nine months ended September 30,2012 due to a decreased DD&A expense rate, partially offset by higher production volumes in 2013. The DD&A expense rate per Boe decreased to $28.13 for the 2013nine months compared to $30.78 during the same period in 2012 due to the effect of the net upward revision in this Partnership’s proved developed producing reserves as of December 31, 2012.

Three months ended September 30, 2013 as compared to three months ended September 30, 2012

DD&A expense for continuing operations decreased approximately $165,000 for the three months ended September 30, 2013 compared to the three months ended September 30, 2012 due to lower production volumes, partially offset by an increased DD&A expense rate in 2013. The DD&A expense rate per Boe increased to $28.13 for the 2013 three months compared to $26.89 during the same period in 2012 due to the effect of the net downward revision in this Partnership’s proved developed producing reserves as of December 31, 2012.

Discontinued Operations

In February 2013, the Managing General Partner entered into a purchase and sale agreement with Caerus, pursuant to which this Partnership agreed to sell to Caerus its Piceance Basin assets and certain derivatives. In June 2013, this divestiture was completed with total consideration to this Partnership of $13.5 million, subject to customary post-closing adjustments. The sale resulted in a loss on divestiture of assets of $0.5 million. In July 2013, this Partnership distributed the proceeds from the Piceance Basin asset divestiture of $13.5 million to the partners. The effective date of the transaction was January 1, 2013. Following the sale to Caerus, this Partnership does not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin assets. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the condensed statement of operations for all periods presented. See Note 8, Divestitures and Discontinued Operations, to the accompanying condensed financial statements included elsewhere in this report for additional information regarding the sale of this Partnership's Piceance Basin assets.

- 16-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The table below presents production data related to this Partnership's Piceance Basin assets that have been divested and that are classified as discontinued operations:

	Three Months Ended September 30,	Nine Months Ended September 30,
Discontinued Operations	2012	2013	2012
Production
Crude oil (Bbl)	699	1,512	2,091
Natural gas (Mcf)	306,039	517,493	928,207
Crude oil equivalent (Boe)	51,705	87,761	156,792

Financial Condition, Liquidity and Capital Resources

This Partnership's primary source of liquidity has been cash flows from operating activities. This source of cash has been primarily used to fund this Partnership's operating costs, direct costs-general and administrative and monthly distributions to the Investor Partners and the Managing General Partner.

Fluctuations in this Partnership's operating cash flows are substantially driven by changes in commodity prices, sales volumes and, historically, realized gains and losses from commodity contracts. Commodity prices have historically been volatile and, through June 30, 2013, the Managing General Partner managed this volatility through the use of derivatives. Therefore, historically, the primary source of cash flows from operations became the net activity between crude oil, natural gas and NGLs sales and realized natural gas derivative gains and losses. This Partnership has no crude oil, natural gas or NGLs derivative positions at September 30, 2013 as all open positions were either sold to Caerus pursuant to the Piceance Basin asset divestiture or liquidated prior to June 30, 2013. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on this Partnership's revenues through September 30, 2013.

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. Crude oil, natural gas and NGLs production from existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, this Partnership anticipates a lower annual level of crude oil, natural gas and NGLs production and, in the absence of significant price increases or additional reserve development, lower revenues. This Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances, decreased production would have a material adverse impact on this Partnership's operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2013 and beyond, and may substantially reduce or restrict this Partnership's ability to participate in Additional Development Plan activities. See this Partnership's 2012 Form 10-K for a description of the Additional Development Plan.

Although the Agreement permits this Partnership to borrow funds on its behalf for Partnership activities, the Managing General Partner does not anticipate electing to fund any portion of this Partnership's Additional Development Plan, which began in 2012, through borrowings. Partnership borrowings, should any occur, will be non-recourse to the Investor Partners. Accordingly, this Partnership, rather than the Investor Partners, will be responsible for repaying any amounts borrowed.

- 17-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Working Capital

At September 30, 2013, this Partnership had working capital of $1.1 million, compared to working capital of $4.6 million at December 31, 2012. The decrease of $3.5 million was primarily due to the following changes:

• accounts receivable decreased by $0.8 million between September 30, 2013 and December 31, 2012;

• realized and unrealized derivative gains receivable decreased by $2.8 million between September 30, 2013 and December 31, 2012; and

• accounts payable and accrued expenses increased by $0.1 million between September 30, 2013 and December 31, 2012.

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

Cash Flows

Operating Activities

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

Net cash flows from operating activities were $6.4 million for the nine months ended September 30, 2013 compared to $5.9 million for the comparable period in 2012. The increase of $0.5 million in cash from operating activities was due primarily to the following:

• an increase in crude oil, natural gas and NGLs sales receipts of $1.5 million;

• a decrease in commodity price risk management realized gain receipts of $0.9 million; and

• an increase in production costs and direct costs-general and administrative payments of $0.1 million.

Investing Activities

Cash flows from investing activities primarily consist of proceeds received from the dispositions of crude oil and natural gas properties, offset by investments in equipment and services. During the nine months ended September 30, 2013, proceeds from the dispositions of crude oil and natural gas properties were approximately $13.5 million. 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. This Partnership may also invest in equipment and services to complete refracturing or recompletion opportunities pursuant to the Additional Development Plan. Substantially all of the $3.1 million 2012 investment is attributable to activities pursuant to the Additional Development Plan.

- 18-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financing Activities

This Partnership initiated monthly cash distributions to investors in May 2008 and has distributed $109.4 million through September 30, 2013. The table below presents cash distributions to this Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to the Managing General Partner for its 37% general partner interest in this Partnership and Investor Partner distributions include amounts distributed to Investor Partners for their 63% ownership share in this Partnership, as well as amounts distributed to the Managing General Partner for limited partnership units repurchased.

Distributions
Three months ended September 30,	Managing General Partner		Investor Partners		Total
2013	$	5,619,476	$	9,568,348	$	15,187,824
2012	505,757		861,152		1,366,909
Nine months ended September 30,	Managing General Partner		Investor Partners		Total
2013	$	7,350,941	$	12,516,468	$	19,867,409
2012	1,593,270		2,712,865		4,306,135

Nine months ended September 30, 2013 as compared to nine months ended September 30, 2012

The increase in distributions for the nine months ended September 30, 2013 as compared to 2012 is primarily due the July 2013 distribution of proceeds received for the Piceance Basin asset divestiture of $13.5 million, including $5.0 million and $8.5 million to the Managing General Partner and the Investor Partners, respectively.

Three months ended September 30, 2013 as compared to three months ended September 30, 2012

The increase in distributions for the three months ended September 30, 2013 as compared to 2012 is primarily due the distribution of proceeds received for the Piceance Basin asset divestiture in July 2013 and an increase in cash flows from operating activities during 2013.

Off-Balance Sheet Arrangements

As of September 30, 2013, this Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on this Partnership's financial condition, results of operations, liquidity, capital expenditures or capital resources.

Commitments and Contingencies

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

Recent Accounting Standards

See Note 2, Recent Accounting Standards, to the accompanying condensed financial statements included elsewhere in this report.

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 2012 Form 10-K.

- 19-

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, 2013, PDC, as Managing General Partner on behalf of this Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of this Partnership's disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that this Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, and that such information is accumulated and communicated to this Partnership's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.

Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and the Chief Financial Officer concluded that this Partnership's disclosure controls and procedures were effective as of September 30, 2013.

(b)    Changes in Internal Control over Financial Reporting

During the three months ended September 30, 2013, 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.

- 20-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1.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.

Item 1A. Risk Factors

Not applicable.

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

Unit Repurchase Program. Beginning in May 2011, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of this Partnership are permitted to request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

The following table presents information about the Managing General Partner's limited partner unit repurchases during the three months ended September 30, 2013:

Period	Total Number of  Units Repurchased	Average Price Paid  Per Unit
July 1-31, 2013	—	$	—
August 1-31, 2013	3.00	4,902
September 1-30, 2013	1.50	5,243
Total	4.50	5,016

Item 3.    Defaults Upon Senior Securities

Not applicable.

Item 4.    Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

None.

- 21-

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

- 22-

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/ James M. Trimble

James M. Trimble

Chief Executive Officer and President

of PDC Energy, Inc.

November 14, 2013

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/ James M. Trimble	Chief Executive Officer and President	November 14, 2013
James M. Trimble	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	November 14, 2013
Gysle R. Shellum	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	November 14, 2013
R. Scott Meyers	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal accounting officer)

- 23-

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James M. Trimble, 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 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 and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor 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 14, 2013

/s/ James M. Trimble

James M. Trimble

Chief Executive Officer and President

PDC Energy, Inc.

Managing General Partner

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Gysle R. Shellum, 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 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 and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor 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 14, 2013

/s/ Gysle R. Shellum

Gysle R. Shellum

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, 2013, 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/ James M. Trimble	November 14, 2013
James M. Trimble
Chief Executive Officer and President
PDC Energy, Inc.
Managing General Partner
/s/ Gysle R. Shellum	November 14, 2013
Gysle R. Shellum
Chief Financial Officer
PDC Energy, Inc.
Managing General Partner

XML

Derivative Financial Instruments Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The following tables present the impact of this Partnership's derivative instruments on this Partnership's accompanying condensed statements of operations:

	Three months ended September 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Gains (Losses) for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Gains and (Losses) for the Current Period			Total
Commodity price risk management loss, net
Realized gains	$	—		$	—		$	—		$	854,344		$	11,105		$	865,449
Unrealized losses	—			—			—			(854,344		)	(363,904		)	(1,218,248		)
Total	$	—		$	—		$	—		$	—		$	(352,799	)	$	(352,799	)
	Nine months ended September 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Losses for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Gains for the Current Period			Total
Commodity price risk management gain (loss), net
Realized gains (losses)	$	1,693,233		$	(417,689	)	$	1,275,544		$	2,264,797		$	581,866		$	2,846,663
Unrealized gains (losses)	(1,693,233		)	—			(1,693,233		)	(2,264,797		)	169,311			(2,095,486		)
Total	$	—		$	(417,689	)	$	(417,689	)	$	—		$	751,177		$	751,177

XML

Condensed Statements of Operations (Unaudited) Statement (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues:
Crude oil, natural gas and NGLs	$ 1,500,286	$ 1,784,184	$ 4,536,215	$ 4,261,718
Commodity price risk management gain (loss), net	0	(352,799)	(417,689)	751,177
Total revenues	1,500,286	1,431,385	4,118,526	5,012,895
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	331,242	281,879	980,150	992,892
Direct costs - general and administrative	42,575	42,510	129,317	124,625
Depreciation, depletion and amortization	761,369	926,048	2,438,069	2,505,337
Accretion of asset retirement obligations	17,229	15,941	50,699	46,911
Total operating costs and expenses	1,152,415	1,266,378	3,598,235	3,669,765
Operating income (loss):
Income from continuing operations	347,871	165,007	520,291	1,343,130
Loss from discontinued operations	0	(293,406)	(33,370)	(967,091)
Net income (loss)	347,871	(128,399)	486,921	376,039
Net income (loss) per Investor Partner Unit:
Continuing operations	$ 49	$ 23	$ 73	$ 189
Discontinued operations	$ 0	$ (41)	$ (4)	$ (136)
Net income (loss) per Investor Partner unit	$ 49	$ (18)	$ 69	$ 53
Investor Partner units outstanding	4,470.00	4,470.00	4,470.00	4,470.00
Managing General Partner
Operating income (loss):
Income from continuing operations	128,712	61,053	192,508	496,958
Loss from discontinued operations	0	(108,560)	(12,347)	(357,824)
Investor Partners
Operating income (loss):
Income from continuing operations	219,159	103,954	327,783	846,172
Loss from discontinued operations	$ 0	$ (184,846)	$ (21,023)	$ (609,267)

XML

Derivative Financial Instruments

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments Disclosure [Text Block]

Derivative Financial Instruments

The following tables present the impact of this Partnership's derivative instruments on this Partnership's accompanying condensed statements of operations:

	Three months ended September 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Gains (Losses) for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Gains and (Losses) for the Current Period			Total
Commodity price risk management loss, net
Realized gains	$	—		$	—		$	—		$	854,344		$	11,105		$	865,449
Unrealized losses	—			—			—			(854,344		)	(363,904		)	(1,218,248		)
Total	$	—		$	—		$	—		$	—		$	(352,799	)	$	(352,799	)
	Nine months ended September 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Losses for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Gains for the Current Period			Total
Commodity price risk management gain (loss), net
Realized gains (losses)	$	1,693,233		$	(417,689	)	$	1,275,544		$	2,264,797		$	581,866		$	2,846,663
Unrealized gains (losses)	(1,693,233		)	—			(1,693,233		)	(2,264,797		)	169,311			(2,095,486		)
Total	$	—		$	(417,689	)	$	(417,689	)	$	—		$	751,177		$	751,177

XML

Fair Value Measurements and Disclosures Fair Value Measurements and Disclosures (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Due from Managing General Partner-derivatives	$ 0	$ 4,409,574
Due to Managing General Partner-derivatives	0	2,004,594
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure		4,409,574
Liabilities, Fair Value Disclosure		2,004,594
Net Asset Fair Value		2,404,980
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Due from Managing General Partner-derivatives		4,409,574
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Due to Managing General Partner-derivatives		$ 2,004,594

XML

Asset Retirement Obligations Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2013

ASSET RETIREMENT OBLIGATIONS [Abstract]

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

Asset Retirement Obligations

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

	Amount
Balance at December 31, 2012	$	1,110,093
Accretion expense	57,576
Obligations discharged with divestiture of properties	(249,424		)
Balance at September 30, 2013	$	918,245

XML

Asset Retirement Obligations Asset Retirement Obligations (Details) (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Changes in asset retirement obligations
Balance at December 31, 2012	$ 1,110,093
Accretion expense	57,576	58,618
Obligations discharged with disposal of properties	(249,424)
Balance at September 30, 2013	$ 918,245

XML

Commitments and Contingencies Commitments and Contingencies (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]
Royalty payment settlement expense	$ 326,000

XML

Derivative Financial Instruments Derivative Financial Instruments (Details) (Commodity Price Risk Management, net [Member], USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Financial Instruments
Realized Gains (Losses)	$ 0	$ 865,449	$ 1,275,544	$ 2,846,663
Unrealized gains (losses)	0	(1,218,248)	(1,693,233)	(2,095,486)
Total	0	(352,799)	(417,689)	751,177
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized [Member]
Derivative Financial Instruments
Realized Gains (Losses)	0	854,344	1,693,233	2,264,797
Unrealized gains (losses)	0	(854,344)	(1,693,233)	(2,264,797)
Total	0	0	0	0
Realized and Unrealized Gains (Losses) for the Current Period [Member]
Derivative Financial Instruments
Realized Gains (Losses)	0	11,105	(417,689)	581,866
Unrealized gains (losses)	0	(363,904)	0	169,311
Total	$ 0	$ (352,799)	$ (417,689)	$ 751,177

XML

General and Basis of Presentation

9 Months Ended

Sep. 30, 2013

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, 2013, there were 1,784 limited partners in this Partnership (the “Investor Partners”). PDC is the designated Managing General Partner of this Partnership and owns a 37% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 63% to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership, and 37% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through September 30, 2013, the Managing General Partner had repurchased 39.3 units of Partnership interest from the Investor Partners at an average price of $4,233 per unit. As of September 30, 2013, the Managing General Partner owned 37.6% of this Partnership.

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 presentation 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 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 2012 Form 10-K. This Partnership's accounting policies are described in the Notes to Financial Statements in this Partnership's 2012 Form 10-K and updated, as necessary, in this Quarterly Report on Form 10-Q. The results of operations and cash flows for the three and nine months ended September 30,2013 are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications had no impact on previously reported results of operations, cash flows or Partners’ equity.

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Transactions with Managing General Partner

9 Months Ended

Sep. 30, 2013

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 the Partners, net of corresponding operating costs and other cash outflows incurred on behalf of this Partnership. The fair value of this Partnership's portion of open derivative instruments were recorded on the condensed December 31, 2012 balance sheet under the captions “Due from Managing General Partner-derivatives” in the case of net unrealized gains and “Due to Managing General Partner-derivatives” in the case of net unrealized losses. As of September 30, 2013, this Partnership had no outstanding derivative instruments.

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

	September 30, 2013			December 31, 2012
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	463,071		$	871,548
Commodity price risk management, realized gain	—			356,531
Other (1)	(409,041		)	(427,481		)
Total Due from Managing General Partner-other, net	$	54,030		$	800,598

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

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner for the three and nine months ended September 30,2013 and 2012. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the condensed statements of operations for continuing operations or in Note 8, Divestitures and Discontinued Operations, for discontinued operations.    

	Three months ended September 30,					Nine months ended September 30,
	2013			2012		2013		2012
Well operations and maintenance	$	273,771		$	522,592	$	1,282,415	$	1,753,939
Gathering, compression and processing fees	(3,807		)	65,812		119,017		267,175
Direct costs - general and administrative	42,575			42,510		455,368		124,625
Refracturing and recompletion costs	—			2,766,186		—		3,126,425
Cash distributions (1)	5,694,280			509,856		7,445,561		1,599,789

(1) Cash distributions include $74,804 and $94,620 during the three and nine months ended September 30, 2013, respectively, and $4,099 and $6,519 during the three and nine months ended September 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC. The increases for 2013 periods over the 2012 periods is attributable to PDC's proportionate share of the distribution of $13.5 million received from the Piceance Basin asset divestiture in 2013.

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

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 gas industry, this Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in this Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews. Liabilities for environmental remediation efforts are included in line item captioned “Accounts payable and accrued expenses” on the condensed balance sheets.

During the nine months ended September 30, 2013, as a result of the Managing General Partner's periodic review, no new environmental remediation liabilities were identified and this Partnership's expense for environmental remediation efforts was not significant. This Partnership's environmental remediation liabilities were insignificant as of September 30, 2013 and December 31, 2012.

The Managing General Partner is not currently aware of any environmental claims existing as of September 30, 2013 which have not been provided for or would otherwise have a material impact on this Partnership's condensed financial statements; however, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on this Partnership's properties.

Royalty Matters

During the three months ended June 30, 2013, this Partnership recognized charges totaling approximately $326,000 related to royalty payment disputes with interest owners in the Piceance Basin. These charges were included in Direct costs - general and administrative expenses within discontinued operations. The settlement charges were allocated to this Partnership based upon historical revenue amounts and were paid during the three months ended September 30, 2013, thereby settling all current and future obligations related to this matter.

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Fair Value Measurements and Disclosures

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Fair Value of Financial Instruments

Determination of fair value. This Partnership's fair value measurements are 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 three levels of inputs that may be used to measure fair value are defined as:

Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.

Derivative instruments that were due to mature subsequent to June 30, 2013 were either liquidated or sold to Caerus Oil and Gas LLC ("Caerus") during the quarter ended June 30, 2013. See Note 8, Divestitures and Discontinued Operations, for additional information regarding transactions with Caerus. Accordingly, as of September 30, 2013, this Partnership did not have any derivative instruments in place for its future production. When applicable, the Managing General Partner measured the fair value of this Partnership's derivative instruments based on a pricing model that utilized market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas forward curve, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validated its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While the Managing General Partner used common industry practices to develop its valuation techniques, and believed this Partnership's valuation method was appropriate and consistent with those used by other market participants, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values.

This Partnership's fixed-price swaps and basis swaps as of December 31, 2012 were included in Level 2. The following table presents this Partnership's derivative assets and liabilities that had been measured at fair value on a recurring basis:

	Balance Sheet	December 31, 2012
	Line Item	Level 2
Assets:
Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	4,409,574
Total assets		4,409,574
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	2,004,594
Total liabilities		2,004,594
Net asset		$	2,404,980

Non-Derivative Financial Assets and Liabilities

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

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Assets Held for Sales, Divestitures and Discontinued Operations Additional Information (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Piceance Basin Assets Divested
Total proceeds from sale of Piceance Basin asset divestiture		$ 13,488,520	$ 0
Proceeds received from sale of Piceance Basin assets	13,500,000
Crude oil and natural gas properties	55,758,995	55,758,995		79,601,649
Accumulated depreciation, depletion and amortization	31,136,270	31,136,270		38,868,788
Piceance and NECO Asset Group [Member]
Piceance Basin Assets Divested
Crude oil and natural gas properties	23,800,000	23,800,000
Accumulated depreciation, depletion and amortization	10,300,000	10,300,000
Loss on disposal of Piceance Basin oil and gas properties	(500,000)
Managing General Partner
Piceance Basin Assets Divested
Proceeds received from sale of Piceance Basin assets	5,000,000
Investor Partners
Piceance Basin Assets Divested
Proceeds received from sale of Piceance Basin assets	$ 8,500,000

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Balance Sheet Parentheticals (Parentheticals)	Sep. 30, 2013	Dec. 31, 2012
Balance Sheet Parentheticals [Abstract]
Limited Partners' Capital Account, Units Issued	4,470.00	4,470.00
Limited Partners' Capital Account, Units Outstanding	4,470.00	4,470.00

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Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2013

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 presentation 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 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 2012 Form 10-K. This Partnership's accounting policies are described in the Notes to Financial Statements in this Partnership's 2012 Form 10-K and updated, as necessary, in this Quarterly Report on Form 10-Q. The results of operations and cash flows for the three and nine months ended September 30,2013 are not necessarily indicative of the results to be expected for the full year or any other future period.

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Condensed Statements of Cash Flows (Unaudited) Statement (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash flows from operating activities:
Net income	$ 486,921	$ 376,039
Adjustments to net income to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	2,593,279	3,843,085
Accretion of asset retirement obligations	57,576	58,618
Change in unrealized loss on derivative transactions	1,693,233	2,095,486
Loss on sale of crude oil and natural gas properties	495,574	0
Changes in assets and liabilities:
Accounts receivable	397,957	(77,131)
Crude oil inventory	(11,028)	(1,979)
Other assets	(32,666)	(32,673)
Accounts payable and accrued expenses	(48,525)	(7,507)
Due from Managing General Partner-other, net	746,568	(360,759)
Net cash from operating activities	6,378,889	5,893,179
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	0	(3,128,044)
Proceeds from sale of crude oil and natural gas properties	13,488,520	0
Net cash from investing activities	13,488,520	(3,128,044)
Cash flows from financing activities:
Distributions to Partners	(19,867,409)	(4,306,135)
Net cash from financing activities	(19,867,409)	(4,306,135)
Net change in cash and cash equivalents	0	(1,541,000)
Cash and cash equivalents, beginning of period	570,376	2,690,377
Cash and cash equivalents, end of period	$ 570,376	$ 1,149,377

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Condensed Balance Sheets (Unaudited) Statement (USD $)	Sep. 30, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 570,376	$ 570,376
Accounts receivable	467,987	865,944
Crude oil inventory	49,053	42,939
Due from Managing General Partner-derivatives	0	4,409,574
Due from Managing General Partner-other, net	54,030	800,598
Total current assets	1,141,446	6,689,431
Crude oil and natural gas properties, successful efforts method, at cost	55,758,995	79,601,649
Less: Accumulated depreciation, depletion and amortization	(31,136,270)	(38,868,788)
Crude oil and natural gas properties, net	24,622,725	40,732,861
Other assets	79,377	46,711
Total Assets	25,843,548	47,469,003
Current liabilities:
Accounts payable and accrued expenses	42,045	90,570
Due to Managing General Partner-derivatives	0	2,004,594
Total current liabilities	42,045	2,095,164
Asset retirement obligations	918,245	1,110,093
Total liabilities	960,290	3,205,257
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	4,012,858	11,183,638
Limited Partners - 4,470 units issued and outstanding	20,870,400	33,080,108
Total Partners' equity	24,883,258	44,263,746
Total Liabilities and Partners' Equity	$ 25,843,548	$ 47,469,003

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Assets Held for Sales, Divestitures and Discontinued Operations Assets Held for Sale, Divestitures and Discontinued Operations (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Operations - Discontinued Operations
Loss from discontinued operations	$ 0	$ (293,406)	$ (33,370)	$ (967,091)
Segment, Discontinued Operations [Member]
Statement of Operations - Discontinued Operations
Crude oil, natural gas and NGL sales		547,394	1,691,225	1,530,684
Crude oil, natural gas and NGL production costs		395,684	740,883	1,148,320
Depreciation, depletion and amortization		441,148	155,210	1,337,748
Direct costs - general and administrative		0	326,051	0
Accretion of asset retirement obligations		3,968	6,877	11,707
Loss on sale of crude oil and natural gas properties		0	495,574	0
Total operating costs and expenses		840,800	1,724,595	2,497,775
Loss from discontinued operations		$ (293,406)	$ (33,370)	$ (967,091)

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Transactions with Managing General Partner Additional Information (Details) (USD $)	Sep. 30, 2013
Additional Information [Abstract]
Derivative Instruments Outstanding as of September 31, 2013	$ 0

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Assets Held for Sales, Divestitures and Discontinued Operations

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

Divestitures and Discontinued Operations

Piceance Basin. In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement with certain affiliates of Caerus, pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $13.5 million, subject to customary post-closing adjustments. The divestiture of this Partnership's Piceance Basin assets resulted in a decrease of crude oil and natural gas properties of $23.8 million and a decrease of accumulated depreciation, depletion and amortization of $10.3 million. The sale resulted in a loss on divestiture of assets of approximately $0.5 million.

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture to the Managing General Partner and Investor Partners as follows:

	Amount
Distributed to:	(millions)
Managing General Partner	$	5.0
Investor Partners	8.5
Total	$	13.5

Following the sale, this Partnership does not have a significant continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the condensed statement of operations for all periods presented.

The following table presents statement of operations data related to this Partnership's discontinued operations for the Piceance Basin divestiture:

	Three Months Ended September 30,			Nine Months Ended September 30,
Statement of Operations - Discontinued Operations	2012			2013			2012
Revenues:
Crude oil, natural gas and NGLs sales	$	547,394		$	1,691,225		$	1,530,684
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	395,684			740,883			1,148,320
Depreciation, depletion and amortization	441,148			155,210			1,337,748
Direct costs - general and administrative expense	—			326,051			—
Accretion of asset retirement obligations	3,968			6,877			11,707
Loss on sale of crude oil and natural gas properties	—			495,574			—
Total operating costs and expenses	840,800			1,724,595			2,497,775
Loss from discontinued operations	$	(293,406	)	$	(33,370	)	$	(967,091	)

While the reclassification of revenues and expenses related to discontinued operations for the prior period had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.

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Fair Value Measurements and Disclosures Fair Value Measurements and Disclosures (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

The following table presents this Partnership's derivative assets and liabilities that had been measured at fair value on a recurring basis:

	Balance Sheet	December 31, 2012
	Line Item	Level 2
Assets:
Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	4,409,574
Total assets		4,409,574
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	2,004,594
Total liabilities		2,004,594
Net asset		$	2,404,980

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Asset Retirement Obligations Asset Retirement Obligations (Notes)

9 Months Ended

Sep. 30, 2013

ASSET RETIREMENT OBLIGATIONS [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

Asset Retirement Obligations

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

	Amount
Balance at December 31, 2012	$	1,110,093
Accretion expense	57,576
Obligations discharged with divestiture of properties	(249,424		)
Balance at September 30, 2013	$	918,245

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Recent Accounting Standards

9 Months Ended

Sep. 30, 2013

New Accounting Pronouncement or Change in Accounting Principle, Current Period Disclosures [Abstract]

Description of New Accounting Pronouncements Adopted [Text Block]

Summary of Significant Accounting Policies

Recently Adopted Accounting Standard

On January 1, 2013, this Partnership adopted changes issued by the Financial Accounting Standards Board regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of the entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. Adoption of these changes had no impact on the condensed financial statements.

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Assets Held for Sales, Divestitures and Discontinued Operations Assets Held for Sale, Divestitures and Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Distributions Made to Managing General Partner and Investor Partners [Table Text Block]

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture to the Managing General Partner and Investor Partners as follows:

	Amount
Distributed to:	(millions)
Managing General Partner	$	5.0
Investor Partners	8.5
Total	$	13.5

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

The following table presents statement of operations data related to this Partnership's discontinued operations for the Piceance Basin divestiture:

	Three Months Ended September 30,			Nine Months Ended September 30,
Statement of Operations - Discontinued Operations	2012			2013			2012
Revenues:
Crude oil, natural gas and NGLs sales	$	547,394		$	1,691,225		$	1,530,684
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	395,684			740,883			1,148,320
Depreciation, depletion and amortization	441,148			155,210			1,337,748
Direct costs - general and administrative expense	—			326,051			—
Accretion of asset retirement obligations	3,968			6,877			11,707
Loss on sale of crude oil and natural gas properties	—			495,574			—
Total operating costs and expenses	840,800			1,724,595			2,497,775
Loss from discontinued operations	$	(293,406	)	$	(33,370	)	$	(967,091	)

While the reclassification of revenues and expenses related to discontinued operations for the prior period had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.

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

9 Months Ended

Sep. 30, 2013

Related Party Transactions [Abstract]

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

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

	September 30, 2013			December 31, 2012
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	463,071		$	871,548
Commodity price risk management, realized gain	—			356,531
Other (1)	(409,041		)	(427,481		)
Total Due from Managing General Partner-other, net	$	54,030		$	800,598

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

Schedule of Related Party Transactions [Table Text Block]

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner for the three and nine months ended September 30,2013 and 2012. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the condensed statements of operations for continuing operations or in Note 8, Divestitures and Discontinued Operations, for discontinued operations.    

	Three months ended September 30,					Nine months ended September 30,
	2013			2012		2013		2012
Well operations and maintenance	$	273,771		$	522,592	$	1,282,415	$	1,753,939
Gathering, compression and processing fees	(3,807		)	65,812		119,017		267,175
Direct costs - general and administrative	42,575			42,510		455,368		124,625
Refracturing and recompletion costs	—			2,766,186		—		3,126,425
Cash distributions (1)	5,694,280			509,856		7,445,561		1,599,789

(1) Cash distributions include $74,804 and $94,620 during the three and nine months ended September 30, 2013, respectively, and $4,099 and $6,519 during the three and nine months ended September 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC. The increases for 2013 periods over the 2012 periods is attributable to PDC's proportionate share of the distribution of $13.5 million received from the Piceance Basin asset divestiture in 2013.

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Transactions with Managing General Partner Related Party Transactions (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Related Party Transaction
Direct costs - general and administrative	$ 42,575		$ 42,510		$ 129,317		$ 124,625
Total proceeds from sale of Piceance Basin asset divestiture					13,488,520		0
Transactions with Managing General Partner
Related Party Transaction
Well operations and maintenance	273,771		522,592		1,282,415		1,753,939
Gathering, compression and processing fees	(3,807)		65,812		119,017		267,175
Direct costs - general and administrative	42,575		42,510		455,368		124,625
Refracturing and recompletion costs	0		2,766,186		0		3,126,425
Cash distributions	5,694,280	[1]	509,856	[1]	7,445,561	[1]	1,599,789	[1]
Distribution Made to Limited Partner, Cash Distributions Paid	74,804		4,099		94,620		6,519
Total proceeds from sale of Piceance Basin asset divestiture	$ 13,500,000

[1] Cash distributions include $74,804 and $94,620 during the three and nine months ended September 30, 2013, respectively, and $4,099 and $6,519 during the three and nine months ended September 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC. The increases for 2013 periods over the 2012 periods is attributable to PDC's proportionate share of the distribution of $13.5 million received from the Piceance Basin asset divestiture in 2013.

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General and Basis of Presentation General and Basis of Presentation (Details) (USD $)	9 Months Ended
	Sep. 30, 2013 Number_of_Limited_Partners
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Investor Partners	1,784
Managing General Partner, Ownership Interest Before Unit Repurchases	37.00%
Investor Partner Ownership Interest	63.00%
Limited Partner Units Repurchased by Managing General Partner	39.3
Average Price Paid for Units Repurchased by Managing General Partner	$ 4,233
Managing General Partner Ownership Interest	37.60%

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Document Entity Information Document	9 Months Ended
	Sep. 30, 2013
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, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	0.00
Additional General Partnership Units Outstanding	0

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Transactions with Managing General Partner Undistributed or Unsettled Transactions With Investor Partners (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
Related Party Transaction
Due from (to) Managing General Partner-other, net	$ 54,030		$ 800,598
Crude oil, natural gas and NGLs sales revenues collected from the Partnership's third-party customers
Related Party Transaction
Due from (to) Managing General Partner-other, net	463,071		871,548
Commodity price risk management, realized gain
Related Party Transaction
Due from (to) Managing General Partner-other, net	0		356,531
Other
Related Party Transaction
Due from (to) Managing General Partner-other, net	$ (409,041)	[1]	$ (427,481)	[1]

[1] All other unsettled transactions, excluding derivative instruments, between this Partnership and the Managing General Partner. The majority of these are operating costs and general and administrative costs, which have not been deducted from distributions.