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 June 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 June 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	12
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21
Item 4.	Controls and Procedures	21
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	22
Item 1A.	Risk Factors	22
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22
Item 3.	Defaults Upon Senior Securities	22
Item 4.	Mine Safety Disclosures	22
Item 5.	Other Information	22
Item 6.	Exhibits	23
	SIGNATURES	24

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 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") 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 relate to, among other things: estimated crude oil, natural gas and natural gas liquids ("NGLs") reserves; future production, expenses, cash flows and liquidity; anticipated capital expenditures and projects; availability of additional midstream facilities and services in the Wattenberg Field and timing and benefits of that availability; the effectiveness of the Managing General Partner's derivative program in providing a degree of price stability; 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 acquire 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;

• this Partnership's future cash flows, liquidity and financial condition;

• competition in 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, particularly 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(“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)

	June 30, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	14,402,278		$	570,376
Accounts receivable	628,545			865,944
Crude oil inventory	41,152			42,939
Due from Managing General Partner-derivatives	—			4,409,574
Due from Managing General Partner-other, net	657,340			800,598
Total current assets	15,729,315			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	(30,374,901		)	(38,868,788		)
Crude oil and natural gas properties, net	25,384,094			40,732,861
Other assets	69,038			46,711
Total Assets	$	41,182,447		$	47,469,003
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	558,220		$	90,570
Due to Managing General Partner-derivatives	—			2,004,594
Total current liabilities	558,220			2,095,164
Asset retirement obligations	901,016			1,110,093
Total liabilities	1,459,236			3,205,257
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	9,503,622			11,183,638
Limited Partners - 4,470 units issued and outstanding	30,219,589			33,080,108
Total Partners' equity	39,723,211			44,263,746
Total Liabilities and Partners' Equity	$	41,182,447		$	47,469,003

See accompanying notes to unaudited condensed financial statements.

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Rockies Region 2007 Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Revenues:
Crude oil, natural gas and NGLs	$	1,368,588		$	998,725		$	3,035,929		$	2,477,534
Commodity price risk management gain (loss), net	69,520			(417,354		)	(417,689		)	1,103,976
Total revenues	1,438,108			581,371			2,618,240			3,581,510
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	340,408			348,155			648,908			711,013
Direct costs - general and administrative	42,093			43,331			86,742			82,115
Depreciation, depletion and amortization	774,788			691,453			1,676,700			1,579,289
Accretion of asset retirement obligations	16,897			15,634			33,470			30,970
Total operating costs and expenses	1,174,186			1,098,573			2,445,820			2,403,387
Income (loss) from continuing operations	263,922			(517,202		)	172,420			1,178,123
Loss from discontinued operations	(253,838		)	(422,500		)	(33,370		)	(673,685		)
Net income (loss)	$	10,084		$	(939,702	)	$	139,050		$	504,438
Income (loss) from continuing operations	$	263,922		$	(517,202	)	$	172,420		$	1,178,123
Less: Managing General Partner interest in income (loss) from continuing operations	97,651			(191,365		)	63,795			435,906
Income (loss) from continuing operations allocated to Investor Partners	$	166,271		$	(325,837	)	$	108,625		$	742,217
Loss from discontinued operations	$	(253,838	)	$	(422,500	)	$	(33,370	)	$	(673,685	)
Less: Managing General Partner interest in loss from discontinued operations	(93,920		)	(156,325		)	(12,347		)	(249,263		)
Loss from discontinued operations allocated to Investor Partners	$	(159,918	)	$	(266,175	)	$	(21,023	)	$	(424,422	)
Net income (loss) per Investor Partner unit
Continuing operations	$	37		$	(73	)	$	24		$	166
Discontinued operations	(36		)	(59		)	(4		)	(95		)
Net income (loss) per Investor Partner unit	$	1		$	(132	)	$	20		$	71
Investor Partner units outstanding	4,470			4,470			4,470			4,470

See accompanying notes to unaudited condensed financial statements.

- 3-

Rockies Region 2007 Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Six months ended June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	139,050		$	504,438
Adjustments to net income to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	1,831,910			2,475,889
Accretion of asset retirement obligations	40,347			38,709
Change in unrealized loss on derivative transactions	1,693,233			877,238
Loss on sale of crude oil and natural gas properties	491,059			—
Changes in assets and liabilities:
Accounts receivable	237,399			292,550
Crude oil inventory	(3,127		)	7,989
Other assets	(22,327		)	(19,134		)
Accounts payable and accrued expenses	3,999			(36,916		)
Due from Managing General Partner-other, net	268,043			100,320
Net cash from operating activities	4,679,586			4,241,083
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	—			(361,858		)
Proceeds from sale of crude oil and natural gas properties	13,831,901			—
Net cash from investing activities	13,831,901			(361,858		)
Cash flows from financing activities:
Distributions to Partners	(4,679,585		)	(2,939,226		)
Net cash from financing activities	(4,679,585		)	(2,939,226		)
Net change in cash and cash equivalents	13,831,902			939,999
Cash and cash equivalents, beginning of period	570,376			2,690,377
Cash and cash equivalents, end of period	$	14,402,278		$	3,630,376
Supplemental disclosure of non-cash activity:
Change in accounts payable and accrued expenses related to disposition of properties and equipment	$	(463,651	)	$	—
Change in due from managing general partner-other,net related to disposition of properties and equipment	124,785			—

See accompanying notes to unaudited condensed financial statements.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2013

(unaudited)

Note 1 - General and Basis of Presentation

Rockies Region 2007 Limited Partnership (“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 Energy, Inc. (“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 June 30, 2013, there were 1,790 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 June 30, 2013, the Managing General Partner had repurchased 34.8 units of Partnership interest from the Investor Partners at an average price of $4,131 per unit. As of June 30, 2013, the Managing General Partner owned 37.5% of this Partnership.

In the Managing General Partner's opinion, the accompanying unaudited 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 six months ended June 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 are mainly attributable to reporting as discontinued operations the results of operations related to the sale of this Partnership's Piceance Basin assets. See Note 8, Divestitures and Discontinued Operations, for additional information regarding the divestiture. The reclassifications had no impact on previously reported cash flows, net income 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 an 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. This Partnership's adoption of these changes had no impact on the unaudited condensed financial statements.

- 5-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 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 balance sheets 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.

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

	June 30, 2013			December 31, 2012
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	883,219		$	871,548
Commodity price risk management, realized gain	293,049			356,531
Other (1)	(518,928		)	(427,481		)
Total Due from Managing General Partner-other, net	$	657,340		$	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 six months ended June 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 June 30,				Six months ended June 30,
	2013		2012		2013		2012
Well operations and maintenance	$	463,931	$	690,773	$	1,008,643	$	1,231,347
Gathering, compression and processing fees	56,575		116,200		122,824		201,363
Direct costs - general and administrative	368,144		43,331		412,793		82,115
Refracturing and recompletion costs	—		360,239		—		360,239
Cash distributions (1)	876,854		562,135		1,751,281		1,089,933

(1) Cash distributions include $10,425 and $19,816 during the three and six months ended June 30, 2013, respectively, and $1,266 and $2,420 during the three and six months ended June 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 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.

The Managing General Partner measures the fair value of this Partnership's derivative instruments based on a pricing model that utilizes 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 validates 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 uses common industry practices to develop its valuation techniques, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 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
	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

Derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated during the quarter ended June 30, 2013. Accordingly, as of June 30, 2013, this Partnership did not have any derivative instruments in place for its future production.

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.

- 8-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2013

(unaudited)

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 June 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Gains for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Losses for the Current Period			Total
Commodity price risk management gain (loss), net
Realized gains (losses)	$	561,768		$	69,520		$	631,288		$	1,120,484		$	(17,336	)	$	1,103,148
Unrealized losses	(561,768		)	—			(561,768		)	(1,120,484		)	(400,018		)	(1,520,502		)
Total	$	—		$	69,520		$	69,520		$	—		$	(417,354	)	$	(417,354	)
	Six months ended June 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, net
Realized gains (losses)	$	1,693,233		$	(417,689	)	$	1,275,544		$	1,562,032		$	419,182		$	1,981,214
Unrealized gains (losses)	(1,693,233		)	—			(1,693,233		)	(1,562,032		)	684,794			(877,238		)
Total	$	—		$	(417,689	)	$	(417,689	)	$	—		$	1,103,976		$	1,103,976

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 sheet.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2013

(unaudited)

During the six months ended June 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 June 30, 2013 and December 31, 2012, respectively.

The Managing General Partner is not currently aware of any environmental claims existing as of June 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. The settlement amount of approximately $304,000 was paid by the Managing General Partner as of June 30, 2013, and is included as a liability in the Due from Managing General Partner-other, net on the balance sheet. The remaining $22,000 is included in Accounts payable and accrued expenses on the balance sheet and represents the Managing General Partner's best estimate relating to the remaining pending dispute regarding various royalty payment issues.

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	40,347
Obligations discharged with disposal of properties	(249,424		)
Balance at June 30, 2013	$	901,016

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 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 ("PSA") with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. Under the same PSA, PDC agreed to sell to Caerus the Piceance Basin assets of PDC and certain other PDC-sponsored partnerships and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $13.8 million, subject to customary post-closing adjustments. The sale resulted in a loss on divestiture of assets of approximately $0.5 million. The Managing General Partner used the proceeds from the asset divestiture for distributions to Partners in July 2013. See Note 9, Subsequent Events, for additional information regarding the use of proceeds received from the Piceance Basin asset sale.

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 unaudited 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 June 30,						Six Months Ended June 30,
Statement of Operations - Discontinued Operations	2013			2012			2013			2012
Revenues:
Crude oil, natural gas and NGLs sales	$	865,054		$	395,169		$	1,692,474		$	983,290
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	299,008			376,970			746,647			752,636
Depreciation, depletion and amortization	—			436,797			155,210			896,600
Direct costs - general and administrative expense	326,051			—			326,051			—
Accretion of asset retirement obligations	2,774			3,902			6,877			7,739
Loss on sale of crude oil and natural gas properties	491,059			—			491,059			—
Total operating costs and expenses	1,118,892			817,669			1,725,844			1,656,975
Loss from discontinued operations	$	(253,838	)	$	(422,500	)	$	(33,370	)	$	(673,685	)

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.

Note 9 - Subsequent Events

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture of $13.8 million to the Partners as follows:

	Amount
	(millions)
Managing General Partner	$	5.1
Investor Partners	8.7
Total	$	13.8

- 11-

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 and natural gas 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. PDC, on behalf of this Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts and/or to utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. 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 Oil and Gas LLC ("Caerus"), pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. Under the same PSA, PDC agreed to sell to Caerus the Piceance Basin assets of PDC and certain other PDC-sponsored partnerships and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. In June 2013, this divestiture was completed with total consideration to this Partnership of approximately $13.8 million, subject to customary post-closing adjustments. The sale resulted in a loss on divestiture of assets of approximately $0.5 million. The effective date of this transaction was January 1, 2013. 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 unaudited condensed statement of operations for all periods presented. In July 2013, this Partnership distributed the proceeds of the sale to its Partners on a pro rata basis.

Partnership Operating Results Overview

Crude oil, natural gas and NGLs sales from continuing operations increased 23%, or $0.6 million, for the first six months of 2013 compared to the first six months of 2012, while sales volumes from continuing operations increased 27% period-to-period. The average sales price per barrel of crude oil equivalent ("Boe"), excluding the impact of realized derivative gains, was $50.94 for the current period compared to $52.75 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 first six months of 2013 compared to $2 million from natural gas derivatives for the first six months of 2012.

- 12-

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 June 30,						Six months ended June 30,
	2013		2012		Change		2013		2012		Change
Number of gross producing wells (end of period)	75		75		—		75		75		—
Production(1)
Crude oil (Bbl)	12,582		10,051		25	%	28,294		23,017		23	%
Natural gas (Mcf)	54,124		38,683		40	%	119,194		88,035		35	%
NGLs (Bbl)	5,940		3,896		52	%	11,443		9,280		23	%
Crude oil equivalent (Boe)(2)	27,542		20,394		35	%	59,602		46,969		27	%
Average Boe per day	303		224		35	%	329		258		27	%
Crude oil, natural gas and NGLs sales
Crude oil	$	1,098,675	$	862,394	27	%	$	2,472,878	$	2,100,026	18	%
Natural gas	193,155		53,429		*		387,683		173,831		123	%
NGLs	76,758		82,902		(7	)%	175,368		203,677		(14	)%
Total crude oil, natural gas and NGLs sales	$	1,368,588	$	998,725	37	%	$	3,035,929	$	2,477,534	23	%
Realized gain on derivatives, net
Natural gas	$	631,287	$	1,103,148	(43	)%	$	1,275,543	$	1,981,214	(36	)%
Total realized gain on derivatives, net	$	631,287	$	1,103,148	(43	)%	$	1,275,543	$	1,981,214	(36	)%
Average selling price (excluding realized gain on derivatives)
Crude oil (per Bbl)	$	87.32	$	85.80	2	%	$	87.40	$	91.24	(4	)%
Natural gas (Mcf)	3.57		1.38		159	%	3.25		1.97		65	%
NGLs (Bbl)	12.92		21.28		(39	)%	15.33		21.95		(30	)%
Crude oil equivalent (per Boe)	49.69		48.97		1	%	50.94		52.75		(3	)%
Average cost per Boe
Crude oil, natural gas and NGLs production cost(3)	$	12.36	$	17.07	(28	)%	$	10.89	$	15.14	(28	)%
Depreciation, depletion and amortization	28.13		33.90		(17	)%	28.13		33.62		(16	)%
Operating costs and expenses
Direct costs - general and administrative	$	42,093	$	43,331	(3	)%	$	86,742	$	82,115	6	%
Depreciation, depletion and amortization	774,788		691,453		12	%	1,676,700		1,579,289		6	%
Cash distributions	$	2,341,650	$	1,515,863	54	%	$	4,679,585	$	2,939,226	59	%

* 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.

- 13-

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 natural gas liquids ("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

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 natural gas sales. This Partnership sells natural gas 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.

During the spring and summer of 2012 and the latter part of the second quarter of 2013 and, to a lesser extent, in some other recent periods, this Partnership's Wattenberg Field production has been adversely impacted by increasing line pressures on the gathering system operated by this Partnership's third-party service provider. The continued acceleration of industry drilling activity, combined with higher temperatures in some periods, have resulted in reduced system compressor efficiency and increased line pressures in the Wattenberg Field. The curtailments that have occurred to date in 2013 are consistent with what the Managing General Partner expected to occur during this period. The Managing General Partner is working closely with the primary midstream provider in the Wattenberg Field who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity. Initial system improvements have already been implemented with the startup of a new field compressor station, 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. The Managing General Partner expects reduced line pressures to substantially benefit this Partnership in late 2013, concurrent with the startup of the LaSalle gas plant and associated field compressor stations. Like most producers, this Partnership relies on its 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 these facilities is beyond this Partnership's or the Managing General Partner's control.

- 14-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Six months ended June 30, 2013 as compared to six months ended June 30, 2012

For the six months ended June 30, 2013 compared to the same period in 2012, crude oil, natural gas and NGLs production from continuing operations, on an energy equivalency-basis, increased 27%, primarily due to increased production from wells refractured or recompleted in accordance with the Additional Development Plan (as discussed in this Partnership's annual report on Form 10-K filed on March 27, 2013) during the three months ended September 30, 2012. The increase from additional development was partially offset by normal production declines for this stage in the wells’ production life cycle and a decrease in production precipitated by curtailments due to high line pressure in the Wattenberg Field.

The approximate $558,000, or 23%, increase in sales from continuing operations for the 2013 six month period as compared to the prior year period was a reflection of sales volume increases of 27%, partially offset by and a decline in the average sales price of 3%. The average sales price per Boe, excluding the impact of realized derivative gains, was $50.94 for the current year six month period compared to $52.75 for the same period a year ago.

Crude oil and natural gas sales from continuing operations for the six months ended June 30, 2013 increased by 18% and 123%, respectively, partially offset by decreased NGLs sales of 14% as compared to the six months ended June 30, 2012. The crude oil sales increase was due primarily to a sales volume increase of 23%, partially offset by a decrease in the average commodity price per Bbl of 4%. The increase in natural gas sales resulted from natural gas production volumes of 35% and increased prices per Mcf of 65%. The decrease in NGLs sales was due to a decrease in the average commodity price per Bbl of 30%, partially offset by an increase of 23% in NGLs production volumes.

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

For the three months ended June 30, 2013 compared to the same period in 2012, crude oil, natural gas and NGLs production from continuing operations, on an energy equivalency-basis, increased 35%, primarily due to increased production from wells refractured or recompleted in accordance with the Additional Development Plan during the three months ended September 30, 2012. The increase from additional development was partially offset by normal production declines for this stage in the wells’ production life cycle and a decrease in production precipitated by curtailments due to high line pressure in the Wattenberg Field.

The approximate $370,000, or 37%, increase in sales from continuing operations for the 2013 three month period as compared to the prior year period was a reflection of sales volume increases of 35%. The average sales price per Boe, excluding the impact of realized derivative gains, was $49.69 for the current year three month period compared to $48.97 for the same period a year ago.

Crude oil and natural gas sales from continuing operations for the three months ended June 30, 2013 increased by 27% and 262%, respectively, partially offset by decreased NGLs sales of 7% as compared to the three months ended June 30, 2012. The increase in crude oil sales was due primarily to a sales volume increase of 25% and, to a lesser extent, an increase in the average commodity price per Bbl of 2%. The decrease in NGLs sales was due to a decrease in the average commodity price per Bbl of 39%, partially offset by a 52% increase in NGLs production volumes. The increase in natural gas sales resulted from higher natural gas production volumes of 40% and increased prices per Mcf of 159%.

Commodity Price Risk Management

This Partnership used various derivative instruments to manage fluctuations in natural gas prices. In late June, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated, which resulted in an approximate $186,000 net realized gain. Realized gains on natural gas, exclusive of basis swaps, of approximately $372,000 were offset by realized losses of approximately $186,000 on this Partnership's basis swap positions. As of June 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.

- 15-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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 unaudited condensed financial statements included elsewhere in this report for additional details of this Partnership's derivative financial instruments.

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

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Commodity price risk management gain (loss), net:
Realized gains
Natural gas	$	631,288		$	1,103,148		$	1,275,544		$	1,981,214
Total realized gains, net	631,288			1,103,148			1,275,544			1,981,214
Unrealized gains (losses)
Reclassification of realized gains included in
prior periods unrealized gains	(561,768		)	(1,120,484		)	(1,693,233		)	(1,562,032		)
Unrealized gains (losses) for the period	—			(400,018		)	—			684,794
Total unrealized losses, net	(561,768		)	(1,520,502		)	(1,693,233		)	(877,238		)
Total commodity price risk management gain (loss), net	$	69,520		$	(417,354	)	$	(417,689	)	$	1,103,976

Six months ended June 30, 2013 as compared to six months ended June 30, 2012

Realized gains of approximately $1.3 million recognized in the six months ended June 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 six months ended June 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 price was narrower than the strike price of this Partnership's basis swaps.

Realized gains of $2 million recognized in the six months ended June 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 six months ended June 30, 2012, realized gains on natural gas, exclusive of basis swaps, were $3.2 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 price was narrower than the strike price of this Partnership's basis swaps.

Unrealized gains of $0.7 million for the six months ended June 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 period ended June 30, 2012, unrealized gains on this Partnership's natural gas positions were $0.8 million, partially offset by unrealized losses on this Partnership's CIG basis swaps of $0.1 million.

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

Realized gains of $0.6 million recognized in the three months ended June 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 three months ended June 30, 2013, realized gains on natural gas, exclusive of basis swaps, were $1.3 million. These gains were offset in part by realized losses of $0.7 million on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

Realized gains of $1.1 million recognized in the three months ended June 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 June 30, 2012, realized gains on natural gas, exclusive of basis swaps, were $1.7 million. These gains were offset in part by realized losses of $0.6 million on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted average price was narrower than the strike price of this Partnership's basis swaps.

- 16-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Unrealized losses of $0.4 million for the three months ended June 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 the narrowing of the CIG basis forward curve. For the period ended June 30, 2012, unrealized losses on this Partnership's natural gas positions were $0.3 million in addition to unrealized losses on this Partnership's CIG basis swaps of $0.1 million.

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 total 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.

Six months ended June 30, 2013 as compared to six months ended June 30, 2012

Crude oil, natural gas and NGLs production costs for the six months ended June 30, 2013decreased approximately $62,000 compared to the same period in 2012 as a result of decreased workover activities partially offset by increased sales production taxes. Crude oil, natural gas and NGLs production costs per Boe decreased to $10.89 during 2013 from $15.14 in 2012 due to higher volumes.

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

Crude oil, natural gas and NGLs production costs for the three months ended June 30, 2013decreased approximately $8,000 compared to the same period in 2012 as a result of decreased workover activities partially offset by increased sales production taxes. Crude oil, natural gas and NGLs production costs per Boe decreased to $12.36 during 2013 from $17.07 in 2012 due to higher volumes.

Depreciation, Depletion and Amortization

Six months ended June 30, 2013 as compared to six months ended June 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 increased approximately $97,000 for the six months ended June 30, 2013 compared to the six months ended June 30,2012 due to higher production volumes partially offset by a decreased DD&A expense rate in 2013. The DD&A expense rate per Boe decreased to $28.13 for the 2013six months compared to $33.62 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 June 30, 2013 as compared to three months ended June 30, 2012

DD&A expense for continuing operations increased approximately $83,000 for the three months ended June 30, 2013 compared to the three months ended June 30, 2012 due to higher production volumes partially offset by a decreased DD&A expense rate in 2013. The DD&A expense rate per Boe decreased to $28.13 for the 2013 three months compared to $33.90 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.

- 17-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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. In June 2013, this divestiture was completed with total consideration to this Partnership of approximately $13.8 million, subject to customary post-closing adjustments. The sale resulted in a loss on divestiture of assets of $0.5 million. 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 unaudited condensed statement of operations for all periods presented. See Note 8, Divestitures and Discontinued Operations, to the accompanying unaudited condensed financial statements included elsewhere in this report for additional information regarding the sale of this Partnership's Piceance Basin assets.

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 June 30,		Six Months Ended June 30,
Discontinued Operations	2013	2012	2013	2012
Production
Crude oil (Bbl)	714	729	1,513	1,392
Natural gas (Mcf)	239,146	302,799	517,493	622,168
Crude oil equivalent (Boe)	40,572	51,196	87,762	105,087

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. For the six months ended June 30, 2013, in addition to the $4.7 million net cash flows from operating activities, this Partnership's liquidity was enhanced by the gross proceeds received from the sale of the Piceance Basin assets of approximately $13.8 million.

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 attempted to manage 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 June 30, 2013 as all open positions were either sold to Caerus pursuant to the Piceance Basin asset divestiture or liquidated during the three months ended 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 June 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.

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.

- 18-

ROCKIES REGION 2007 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Working Capital

At June 30, 2013, this Partnership had working capital of $15.2 million, compared to working capital of $4.6 million at December 31, 2012. The increase of $10.6 million was primarily due to the following changes:

• cash and cash equivalents increased, primarily due to the sale of the Piceance Basin assets to Caerus, by $13.8 million between June 30, 2013 and December 31, 2012;

• accounts receivable decreased by $0.2 million between June 30, 2013 and December 31, 2012;

• realized and unrealized derivative gains receivable decreased by $2.5 million between June 30, 2013 and December 31, 2012;

• accounts payable and accrued expenses increased by $0.5 million between June 30, 2013 and December 31, 2012; and

• amounts due to Managing General Partner-other, net, excluding crude oil, natural gas and NGLs sales received from third parties and realized derivative gains, increased by $0.1 million between June 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 $4.7 million for the six months ended June 30, 2013 compared to $4.2 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 $0.9 million;

• a decrease in commodity price risk management realized gain receipts of $0.2 million; and

• a decrease in production costs and direct costs-general and administrative payments of $0.3 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 six months ended June 30, 2013, proceeds from the dispositions of crude oil and natural gas properties were approximately $13.8 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. Substantially all of the $0.4 million 2012 investment is attributable to activities pursuant to the Additional Development Plan.

- 19-

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 $94.2 million through June 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 June 30,	Managing General Partner		Investor Partners		Total
2013	$	866,429	$	1,475,221	$	2,341,650
2012	560,869		954,994		1,515,863
Six months ended June 30,	Managing General Partner		Investor Partners		Total
2013	$	1,731,465	$	2,948,120	$	4,679,585
2012	1,087,513		1,851,713		2,939,226

Six months ended June 30, 2013 as compared to six months ended June 30, 2012

The increase in distributions for the six months ended June 30, 2013 as compared to 2012 is primarily due to an increase in cash flows from operating activities during 2013.

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

The increase in distributions for the three months ended June 30, 2013 as compared to 2012 is primarily due to an increase in cash flows from operating activities during 2013.

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture of $13.8 million including $8.7 million and $5.1 million to the Investor Partners and the Managing General Partner, respectively.

Off-Balance Sheet Arrangements

As of June 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 unaudited condensed financial statements included elsewhere in this report.

Recent Accounting Standards

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

Critical Accounting Policies and Estimates

The preparation of the accompanying unaudited 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.

- 20-

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 June 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 June 30, 2013.

(b)    Changes in Internal Control over Financial Reporting

During the three months ended June 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.

- 21-

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 may 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 June 30, 2013:

Period	Total Number of  Units Repurchased	Average Price Paid  Per Unit
April 1-30, 2013	—	$	—
May 1-31, 2013	3.00	4,308
June 1-30, 2013	3.25	4,703
Total	6.25	4,514

Item 3.    Defaults Upon Senior Securities

Not applicable.

Item 4.    Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

None.

- 22-

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
10.1	Purchase and Sale Agreement by and among PDC Energy, Inc., affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated February 4, 2013.	10-Q	000-07246	10.1	5/1/2013
10.2	Amendment No. 1 to Purchase and Sale Agreement by and among PDC Energy, Inc., affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated May 30, 2013.	10-Q	000-07246	10.1	6/3/2013
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
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

*Furnished herewith.

- 23-

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.

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

- 24-

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:  August 14, 2013

/s/ James M. Trimble

James M. Trimble

Chief Executive Officer

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

XML

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

6 Months Ended

Jun. 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
	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

XML

Condensed Statements of Operations (Unaudited) Statement (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Revenues:
Crude oil, natural gas and NGLs	$ 1,368,588	$ 998,725	$ 3,035,929	$ 2,477,534
Commodity price risk management gain (loss), net	69,520	(417,354)	(417,689)	1,103,976
Total revenues	1,438,108	581,371	2,618,240	3,581,510
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	340,408	348,155	648,908	711,013
Direct costs - general and administrative	42,093	43,331	86,742	82,115
Depreciation, depletion and amortization	774,788	691,453	1,676,700	1,579,289
Accretion of asset retirement obligations	16,897	15,634	33,470	30,970
Total operating costs and expenses	1,174,186	1,098,573	2,445,820	2,403,387
Income (loss) from operations:
Income (loss) from continuing operations	263,922	(517,202)	172,420	1,178,123
Loss from discontinued operations	(253,838)	(422,500)	(33,370)	(673,685)
Net income (loss)	10,084	(939,702)	139,050	504,438
Net income (loss) per Investor Partner Unit:
Continuing operations	$ 37	$ (73)	$ 24	$ 166
Discontinued operations	$ (36)	$ (59)	$ (4)	$ (95)
Net income (loss) per Investor Partner unit	$ 1	$ (132)	$ 20	$ 71
Investor Partner units outstanding	4,470.00	4,470	4,470.00	4,470
Managing General Partner
Income (loss) from operations:
Income (loss) from continuing operations	97,651	(191,365)	63,795	435,906
Loss from discontinued operations	(93,920)	(156,325)	(12,347)	(249,263)
Investor Partners
Income (loss) from operations:
Income (loss) from continuing operations	166,271	(325,837)	108,625	742,217
Loss from discontinued operations	$ (159,918)	$ (266,175)	$ (21,023)	$ (424,422)

XML

Derivative Financial Instruments

6 Months Ended

Jun. 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 June 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Gains for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Losses for the Current Period			Total
Commodity price risk management gain (loss), net
Realized gains (losses)	$	561,768		$	69,520		$	631,288		$	1,120,484		$	(17,336	)	$	1,103,148
Unrealized losses	(561,768		)	—			(561,768		)	(1,120,484		)	(400,018		)	(1,520,502		)
Total	$	—		$	69,520		$	69,520		$	—		$	(417,354	)	$	(417,354	)
	Six months ended June 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, net
Realized gains (losses)	$	1,693,233		$	(417,689	)	$	1,275,544		$	1,562,032		$	419,182		$	1,981,214
Unrealized gains (losses)	(1,693,233		)	—			(1,693,233		)	(1,562,032		)	684,794			(877,238		)
Total	$	—		$	(417,689	)	$	(417,689	)	$	—		$	1,103,976		$	1,103,976

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Transactions with Managing General Partner Related Party Transactions (Details) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2013		Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012
Related Party Transaction
Direct costs - general and administrative	$ 42,093		$ 43,331		$ 86,742		$ 82,115
Transactions with Managing General Partner
Related Party Transaction
Well operations and maintenance	463,931		690,773		1,008,643		1,231,347
Gathering, compression and processing fees	56,575		116,200		122,824		201,363
Direct costs - general and administrative	368,144		43,331		412,793		82,115
Refracturing and recompletion costs	0		360,239		0		360,239
Cash distributions	876,854	[1]	562,135	[1]	1,751,281	[1]	1,089,933	[1]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 10,425		$ 1,266		$ 19,816		$ 2,420

[1] Cash distributions include $10,425 and $19,816 during the three and six months ended June 30, 2013, respectively, and $1,266 and $2,420 during the three and six months ended June 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.

XML

Derivative Financial Instruments Derivative Financial Instruments (Tables)

6 Months Ended

Jun. 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 June 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Gains for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Losses for the Current Period			Total
Commodity price risk management gain (loss), net
Realized gains (losses)	$	561,768		$	69,520		$	631,288		$	1,120,484		$	(17,336	)	$	1,103,148
Unrealized losses	(561,768		)	—			(561,768		)	(1,120,484		)	(400,018		)	(1,520,502		)
Total	$	—		$	69,520		$	69,520		$	—		$	(417,354	)	$	(417,354	)
	Six months ended June 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, net
Realized gains (losses)	$	1,693,233		$	(417,689	)	$	1,275,544		$	1,562,032		$	419,182		$	1,981,214
Unrealized gains (losses)	(1,693,233		)	—			(1,693,233		)	(1,562,032		)	684,794			(877,238		)
Total	$	—		$	(417,689	)	$	(417,689	)	$	—		$	1,103,976		$	1,103,976

XML

Commitments and Contingencies Commitments and Contingencies (Details) (USD $)	3 Months Ended
	Jun. 30, 2013
Commitments and Contingencies Disclosure [Abstract]
Royalty payment settlements expense	$ 326,000
Payments for Royalties	304,000
Accrued royalty payment settlement	$ 22,000

XML

Derivative Financial Instruments Derivative Financial Instruments (Details) (Commodity Price Risk Management, net, USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Derivative Financial Instruments
Realized Gains (Losses)	$ 631,288	$ 1,103,148	$ 1,275,544	$ 1,981,214
Unrealized gains (losses)	(561,768)	(1,520,502)	(1,693,233)	(877,238)
Total	69,520	(417,354)	(417,689)	1,103,976
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
Derivative Financial Instruments
Realized Gains (Losses)	561,768	1,120,484	1,693,233	1,562,032
Unrealized gains (losses)	(561,768)	(1,120,484)	(1,693,233)	(1,562,032)
Total	0	0	0	0
Realized and Unrealized Gains (Losses) for the Current Period
Derivative Financial Instruments
Realized Gains (Losses)	69,520	(17,336)	(417,689)	419,182
Unrealized gains (losses)	0	(400,018)	0	684,794
Total	$ 69,520	$ (417,354)	$ (417,689)	$ 1,103,976

XML

Subsequent Events (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Jun. 30, 2013
Subsequent Event [Line Items]
Payments of Capital Distribution	$ 13.8
Managing General Partner
Subsequent Event [Line Items]
Payments of Capital Distribution	5.1
Investor Partners
Subsequent Event [Line Items]
Payments of Capital Distribution	$ 8.7

XML

Fair Value Measurements and Disclosures Fair Value Measurements and Disclosures (Details) (USD $)	Jun. 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

General and Basis of Presentation

6 Months Ended

Jun. 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 (“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 Energy, Inc. (“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 June 30, 2013, there were 1,790 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 June 30, 2013, the Managing General Partner had repurchased 34.8 units of Partnership interest from the Investor Partners at an average price of $4,131 per unit. As of June 30, 2013, the Managing General Partner owned 37.5% of this Partnership.

In the Managing General Partner's opinion, the accompanying unaudited 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 six months ended June 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 are mainly attributable to reporting as discontinued operations the results of operations related to the sale of this Partnership's Piceance Basin assets. See Note 8, Divestitures and Discontinued Operations, for additional information regarding the divestiture. The reclassifications had no impact on previously reported cash flows, net income or Partners’ equity.

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Transactions with Managing General Partner

6 Months Ended

Jun. 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 balance sheets 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.

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

	June 30, 2013			December 31, 2012
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	883,219		$	871,548
Commodity price risk management, realized gain	293,049			356,531
Other (1)	(518,928		)	(427,481		)
Total Due from Managing General Partner-other, net	$	657,340		$	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 six months ended June 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 June 30,				Six months ended June 30,
	2013		2012		2013		2012
Well operations and maintenance	$	463,931	$	690,773	$	1,008,643	$	1,231,347
Gathering, compression and processing fees	56,575		116,200		122,824		201,363
Direct costs - general and administrative	368,144		43,331		412,793		82,115
Refracturing and recompletion costs	—		360,239		—		360,239
Cash distributions (1)	876,854		562,135		1,751,281		1,089,933

(1) Cash distributions include $10,425 and $19,816 during the three and six months ended June 30, 2013, respectively, and $1,266 and $2,420 during the three and six months ended June 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.

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Commitments and Contingencies

6 Months Ended

Jun. 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 sheet.

During the six months ended June 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 June 30, 2013 and December 31, 2012, respectively.

The Managing General Partner is not currently aware of any environmental claims existing as of June 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. The settlement amount of approximately $304,000 was paid by the Managing General Partner as of June 30, 2013, and is included as a liability in the Due from Managing General Partner-other, net on the balance sheet. The remaining $22,000 is included in Accounts payable and accrued expenses on the balance sheet and represents the Managing General Partner's best estimate relating to the remaining pending dispute regarding various royalty payment issues.

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Fair Value Measurements and Disclosures

6 Months Ended

Jun. 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.

The Managing General Partner measures the fair value of this Partnership's derivative instruments based on a pricing model that utilizes 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 validates 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 uses common industry practices to develop its valuation techniques, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.

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
	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

Derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated during the quarter ended June 30, 2013. Accordingly, as of June 30, 2013, this Partnership did not have any derivative instruments in place for its future production.

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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Asset Retirement Obligations Asset Retirement Obligations (Details) (USD $)	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Changes in asset retirement obligations
Balance at December 31, 2012	$ 1,110,093
Accretion expense	40,347	38,709
Obligations discharged with disposal of properties	(249,424)
Balance at June 30, 2013	$ 901,016

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Balance Sheet Parentheticals (Parentheticals)	Jun. 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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Subsequent Events (Notes)

6 Months Ended

Jun. 30, 2013

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Subsequent Events

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture of $13.8 million to the Partners as follows:

	Amount
	(millions)
Managing General Partner	$	5.1
Investor Partners	8.7
Total	$	13.8

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Condensed Statements of Cash Flows (Unaudited) Statement (USD $)	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Cash flows from operating activities:
Net income	$ 139,050	$ 504,438
Adjustments to net income to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	1,831,910	2,475,889
Accretion of asset retirement obligations	40,347	38,709
Change in unrealized loss on derivative transactions	1,693,233	877,238
Loss on sale of crude oil and natural gas properties	491,059	0
Changes in assets and liabilities:
Accounts receivable	237,399	292,550
Crude oil inventory	(3,127)	7,989
Other assets	(22,327)	(19,134)
Accounts payable and accrued expenses	3,999	(36,916)
Due from Managing General Partner-other, net	268,043	100,320
Net cash from operating activities	4,679,586	4,241,083
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	0	(361,858)
Proceeds from Sale of crude oil and natural gas properties	13,831,901	0
Net cash from investing activities	13,831,901	(361,858)
Cash flows from financing activities:
Distributions to Partners	(4,679,585)	(2,939,226)
Net cash from financing activities	(4,679,585)	(2,939,226)
Net change in cash and cash equivalents	13,831,902	939,999
Cash and cash equivalents, beginning of period	570,376	2,690,377
Cash and cash equivalents, end of period	14,402,278	3,630,376
Supplemental disclosure of non-cash activity:
Change in accounts payable related to asset disposal	(463,651)	0
Change in accounts receivable due to asset disposal	$ 124,785	$ 0

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Condensed Balance Sheets (Unaudited) Statement (USD $)	Jun. 30, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 14,402,278	$ 570,376
Accounts receivable	628,545	865,944
Crude oil inventory	41,152	42,939
Due from Managing General Partner-derivatives	0	4,409,574
Due from Managing General Partner-other, net	657,340	800,598
Total current assets	15,729,315	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	(30,374,901)	(38,868,788)
Crude oil and natural gas properties, net	25,384,094	40,732,861
Other assets	69,038	46,711
Total Assets	41,182,447	47,469,003
Current liabilities:
Accounts payable and accrued expenses	558,220	90,570
Due to Managing General Partner-derivatives	0	2,004,594
Total current liabilities	558,220	2,095,164
Asset retirement obligations	901,016	1,110,093
Total liabilities	1,459,236	3,205,257
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	9,503,622	11,183,638
Limited Partners - 4,470 units issued and outstanding	30,219,589	33,080,108
Total Partners' equity	39,723,211	44,263,746
Total Liabilities and Partners' Equity	$ 41,182,447	$ 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		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Statement of Operations - Discontinued Operations
Loss from discontinued operations	$ (253,838)	$ (422,500)	$ (33,370)	$ (673,685)
Segment, Discontinued Operations [Member]
Statement of Operations - Discontinued Operations
Crude oil, natural gas and NGLs sales	865,054	395,169	1,692,474	983,290
Crude oil, natural gas and NGLs production costs	299,008	376,970	746,647	752,636
Depreciation, depletion and amortization	0	436,797	155,210	896,600
Direct costs - general and administrative expense	326,051	0	326,051	0
Accretion of asset retirement obligations	2,774	3,902	6,877	7,739
Loss on sale of crude oil and natural gas properties	491,059	0	491,059	0
Total operating costs and expenses	1,118,892	817,669	1,725,844	1,656,975
Loss from discontinued operations	$ (253,838)	$ (422,500)	$ (33,370)	$ (673,685)

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Transactions with Managing General Partner Undistributed or Unsettled Transactions With Investor Partners (Details) (USD $)	Jun. 30, 2013		Dec. 31, 2012
Related Party Transaction
Due from (to) Managing General Partner-other, net	$ 657,340		$ 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	883,219		871,548
Commodity price risk management, realized gain
Related Party Transaction
Due from (to) Managing General Partner-other, net	293,049		356,531
Other
Related Party Transaction
Due from (to) Managing General Partner-other, net	$ (518,928)	[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.

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Assets Held for Sales, Divestitures and Discontinued Operations

6 Months Ended

Jun. 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 ("PSA") with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. Under the same PSA, PDC agreed to sell to Caerus the Piceance Basin assets of PDC and certain other PDC-sponsored partnerships and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $13.8 million, subject to customary post-closing adjustments. The sale resulted in a loss on divestiture of assets of approximately $0.5 million. The Managing General Partner used the proceeds from the asset divestiture for distributions to Partners in July 2013. See Note 9, Subsequent Events, for additional information regarding the use of proceeds received from the Piceance Basin asset sale.

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 unaudited 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 June 30,						Six Months Ended June 30,
Statement of Operations - Discontinued Operations	2013			2012			2013			2012
Revenues:
Crude oil, natural gas and NGLs sales	$	865,054		$	395,169		$	1,692,474		$	983,290
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	299,008			376,970			746,647			752,636
Depreciation, depletion and amortization	—			436,797			155,210			896,600
Direct costs - general and administrative expense	326,051			—			326,051			—
Accretion of asset retirement obligations	2,774			3,902			6,877			7,739
Loss on sale of crude oil and natural gas properties	491,059			—			491,059			—
Total operating costs and expenses	1,118,892			817,669			1,725,844			1,656,975
Loss from discontinued operations	$	(253,838	)	$	(422,500	)	$	(33,370	)	$	(673,685	)

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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Assets Held for Sales, Divestitures and Discontinued Operations Additional Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Jun. 30, 2013
Discontinued Operations and Disposal Groups [Abstract]
Consideration received from sale of Piceance Basin oil and gas properties	$ 13.8
Loss on disposition of Piceance Basin oil and gas properties	$ 0.5

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

6 Months Ended

Jun. 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 sheet line item “Due from Managing General Partner-other, net” which remain undistributed or unsettled with this Partnership's investors as of the dates indicated:

	June 30, 2013			December 31, 2012
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	883,219		$	871,548
Commodity price risk management, realized gain	293,049			356,531
Other (1)	(518,928		)	(427,481		)
Total Due from Managing General Partner-other, net	$	657,340		$	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 six months ended June 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 June 30,				Six months ended June 30,
	2013		2012		2013		2012
Well operations and maintenance	$	463,931	$	690,773	$	1,008,643	$	1,231,347
Gathering, compression and processing fees	56,575		116,200		122,824		201,363
Direct costs - general and administrative	368,144		43,331		412,793		82,115
Refracturing and recompletion costs	—		360,239		—		360,239
Cash distributions (1)	876,854		562,135		1,751,281		1,089,933

(1) Cash distributions include $10,425 and $19,816 during the three and six months ended June 30, 2013, respectively, and $1,266 and $2,420 during the three and six months ended June 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.

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Asset Retirement Obligations Asset Retirement Obligations (Notes)

6 Months Ended

Jun. 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	40,347
Obligations discharged with disposal of properties	(249,424		)
Balance at June 30, 2013	$	901,016

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Recent Accounting Standards

6 Months Ended

Jun. 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 an 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. This Partnership's adoption of these changes had no impact on the unaudited condensed financial statements.

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Asset Retirement Obligations Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 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	40,347
Obligations discharged with disposal of properties	(249,424		)
Balance at June 30, 2013	$	901,016

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Significant Accounting Policies (Policies)

6 Months Ended

Jun. 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 unaudited 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 six months ended June 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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General and Basis of Presentation General and Basis of Presentation (Details) (USD $)	6 Months Ended
	Jun. 30, 2013 Number_of_Limited_Partners
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Investor Partners	1,790
Managing General Partner, Ownership Interest Before Unit Repurchases	37.00%
Investor Partner Ownership Interest	63.00%
Limited Partner Units Repurchased by Managing General Partner	34.8
Average Price Paid for Units Repurchased by Managing General Partner	$ 4,131
Managing General Partner Ownership Interest	37.50%

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

6 Months Ended

Jun. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

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 June 30,						Six Months Ended June 30,
Statement of Operations - Discontinued Operations	2013			2012			2013			2012
Revenues:
Crude oil, natural gas and NGLs sales	$	865,054		$	395,169		$	1,692,474		$	983,290
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	299,008			376,970			746,647			752,636
Depreciation, depletion and amortization	—			436,797			155,210			896,600
Direct costs - general and administrative expense	326,051			—			326,051			—
Accretion of asset retirement obligations	2,774			3,902			6,877			7,739
Loss on sale of crude oil and natural gas properties	491,059			—			491,059			—
Total operating costs and expenses	1,118,892			817,669			1,725,844			1,656,975
Loss from discontinued operations	$	(253,838	)	$	(422,500	)	$	(33,370	)	$	(673,685	)

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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Document Entity Information Document	6 Months Ended
	Jun. 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	Jun. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding	0.00
Additional General Partnership Units Outstanding	0

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Subsequent Events (Tables)

6 Months Ended

Jun. 30, 2013

Subsequent Events [Abstract]

Schedule of Subsequent Events [Table Text Block]

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture of $13.8 million to the Partners as follows:

	Amount
	(millions)
Managing General Partner	$	5.1
Investor Partners	8.7
Total	$	13.8