Attached files

file filename
EXCEL - IDEA: XBRL DOCUMENT - ROCKIES REGION 2007 LPFinancial_Report.xls
EX-31.2 - ROCKIES REGION 2007 LPrr07lp-ex312_20110630.htm
EX-32.1 - ROCKIES REGION 2007 LPrr07lp-ex321_20110630.htm
EX-31.1 - ROCKIES REGION 2007 LPrr07lp-ex311_20110630.htm



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, 2011
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)

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

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 Web site, 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 the 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
 

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, 2011 the Partnership had 4,470 units of limited partnership interest and no units of additional general partnership interest outstanding.

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

PART I – FINANCIAL INFORMATION
 
 
Page
 
Item 1.
Financial Statements (unaudited)
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
PART II – OTHER INFORMATION
 
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
 
 
 
 



SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic 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 Rockies Region 2007 Limited Partnership's (“Partnership” or the “Registrant”) business, financial condition and results of operations. Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the 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 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 include: estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves; drilling plans; future cash flows and anticipated liquidity; anticipated capital expenditures; the adequacy of the Managing General Partner's casualty insurance coverage; the effectiveness of the Managing General Partner's derivative policies in achieving the Partnership's risk management objectives; and the Managing General Partner's 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 natural gas, NGLs and crude oil, 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;
volatility of commodity prices for natural gas, NGLs and crude oil;
changes in estimates of proved reserves;
inaccuracy of reserve estimates and expected production rates;
declines in the value of the Partnership's natural gas and crude oil properties resulting in impairments;
the availability of Partnership future cash flows for investor distributions or funding of additional Codell formation development activities;
the timing and extent of the Partnership's success in further developing and producing the Partnership's reserves;
the Managing General Partner's ability to acquire drilling rig services, supplies and services at reasonable prices;
risks incidental to the additional Codell formation development and operation of natural gas and crude oil wells;
the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on price;
changes in environmental laws, the regulation and enforcement of those laws and the costs to comply with those laws;
the impact of environmental events, governmental responses to the events and the Managing General Partner's ability to insure adequately against such events;
the timing and receipt of necessary regulatory permits;
competition in the oil and gas industry;
the success of the Managing General Partner in marketing the Partnership's natural gas, NGLs and crude oil;
the effect of natural gas and crude oil derivative activities;
the cost of pending or future litigation;
the Managing General Partner's ability to retain or attract senior management and key technical employees; and
the success of strategic plans, expectations and objectives for future operations of the Managing General Partner.
Further, the Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this report, the Partnership's annual report on Form 10-K for the year ended December 31, 2010 filed with the United States Securities and Exchange Commission (“SEC”) on March 30, 2011 (“2010 Form 10-K”) and the Partnership's other filings with the SEC for further information on risks and uncertainties that could affect the Partnership's business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The 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 (unaudited)

Rockies Region 2007 Limited Partnership
Condensed Balance Sheets
(unaudited)

 
June 30, 2011
 
December 31, 2010*
Assets
 
 
 

 
 
 
 
Current assets:
 
 
 

Cash and cash equivalents
$
1,290,377

 
$
690,377

Accounts receivable
851,727

 
1,175,972

Crude oil inventory
99,926

 
59,031

Due from Managing General Partner-derivatives
3,330,864

 
3,178,313

Due from Managing General Partner-other, net
373,503

 
534,115

Total current assets
5,946,397

 
5,637,808

 
 
 
 
Natural gas and crude oil properties, successful efforts method, at cost
79,962,406

 
79,934,322

Less: Accumulated depreciation, depletion and amortization
(32,444,712
)
 
(29,699,641
)
Natural gas and crude oil properties, net
47,517,694

 
50,234,681

 
 
 
 
Due from Managing General Partner-derivatives
3,727,281

 
4,689,041

Total noncurrent assets
51,244,975

 
54,923,722

 
 
 
 
Total Assets
$
57,191,372

 
$
60,561,530

 
 
 
 
Liabilities and Partners' Equity
 
 
 
 
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
99,992

 
$
136,704

Due to Managing General Partner-derivatives
2,610,927

 
2,580,843

Total current liabilities
2,710,919

 
2,717,547

 
 
 
 
Due to Managing General Partner-derivatives
2,684,786

 
3,556,891

Asset retirement obligations
752,822

 
727,952

Total liabilities
6,148,527

 
7,002,390

 
 
 
 
Commitments and contingent liabilities


 


 
 
 
 
Partners' equity:
 
 
 
   Managing General Partner
13,691,904

 
14,622,934

   Limited Partners - 4,470 units issued and outstanding
37,350,941

 
38,936,206

Total Partners' equity
51,042,845

 
53,559,140

 
 
 
 
Total Liabilities and Partners' Equity
$
57,191,372

 
$
60,561,530

    *Derived from audited 2010 balance sheet

See accompanying notes to unaudited condensed financial statements.

-2-

Rockies Region 2007 Limited Partnership
Condensed Statements of Operations
(unaudited)

 
Three months ended June 30,
 
Six months ended June 30,
 
2011
 
2010
 
2011
 
2010
Revenues:
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil sales
$
2,526,088

 
$
3,352,184

 
$
5,780,804

 
$
8,254,343

Commodity price risk management gain, net
796,963

 
1,448,531

 
389,634

 
5,921,820

Total revenues
3,323,051

 
4,800,715

 
6,170,438

 
14,176,163

 
 
 
 
 
 
 
 
Operating costs and expenses:
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil production costs
1,009,282

 
1,621,604

 
2,499,885

 
2,511,159

Direct costs - general and administrative
39,796

 
44,447

 
87,046

 
81,975

Depreciation, depletion and amortization
1,242,257

 
2,379,771

 
2,745,071

 
4,973,089

Accretion of asset retirement obligations
12,540

 
11,725

 
24,870

 
23,254

Total operating costs and expenses
2,303,875

 
4,057,547

 
5,356,872

 
7,589,477

 
 
 
 
 
 
 
 
Net income from operations
$
1,019,176

 
$
743,168

 
$
813,566

 
$
6,586,686

 
 
 
 
 
 
 
 
Net income allocated to partners
$
1,019,176

 
$
743,168

 
$
813,566

 
$
6,586,686

Less: Managing General Partner interest in net income
377,095

 
274,972

 
301,019

 
2,437,074

Net income allocated to Investor Partners
$
642,081

 
$
468,196

 
$
512,547

 
$
4,149,612

 
 
 
 
 
 
 
 
Net income per Investor Partner unit
$
144

 
$
105

 
$
115

 
$
928

 
 
 
 
 
 
 
 
Investor Partner units outstanding
4,470.00

 
4,470.00

 
4,470.00

 
4,470.00

















See accompanying notes to unaudited condensed financial statements.

-3-

Rockies Region 2007 Limited Partnership
Condensed Statements of Cash Flows
(unaudited)

 
Six months ended June 30,
 
2011
 
2010
Cash flows from operating activities:
 
 
 
Net income
$
813,566

 
$
6,586,686

Adjustments to net income to reconcile to net cash
   provided by operating activities:
 
 
 
Depreciation, depletion and amortization
2,745,071

 
4,973,089

Accretion of asset retirement obligations
24,870

 
23,254

Unrealized gain on derivative transactions
(32,812
)
 
(3,562,776
)
Changes in operating assets and liabilities:
 
 
 
Decrease in accounts receivable
324,245

 
375,847

Increase in crude oil inventory
(40,895
)
 
(599
)
Increase (decrease) in accounts payable and accrued expenses
(36,712
)
 
1,115

Decrease in Due from Managing General Partner - other, net
160,612

 
1,895,898

Net cash provided by operating activities
3,957,945

 
10,292,514

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures for natural gas and crude oil properties
(28,084
)
 
(81,157
)
Net cash used in investing activities
(28,084
)
 
(81,157
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Distributions to Partners
(3,329,861
)
 
(10,211,444
)
Net cash used in financing activities
(3,329,861
)
 
(10,211,444
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
600,000

 
(87
)
Cash and cash equivalents, beginning of period
690,377

 
4,229

Cash and cash equivalents, end of period
$
1,290,377

 
$
4,142















See accompanying notes to unaudited condensed financial statements.

-4-

ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)


Note 1−General and Basis of Presentation

Rockies Region 2007 Limited Partnership (the “Partnership” or the “Registrant”) was organized 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 natural gas and crude oil properties. Business operations of the Partnership commenced upon closing of an offering for the private placement of Partnership units. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the 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 the Partnership and initiates and completes substantially all Partnership transactions.

As of June 30, 2011, there were 1,796 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 37% Managing General Partner ownership in the Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of the Partnership are allocated 63% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the 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, 2011, the Managing General Partner has repurchased no units of Partnership interests from the Investor Partners. As of June 30, 2011, the Managing General Partner owns 37% of the Partnership.

The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership's wells are depleted or become uneconomical to produce, at which time they may be sold or plugged, reclaimed and abandoned. The Partnership's maximum term of existence extends through December 31, 2057, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

In the Managing General Partner's opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of the Partnership's financial statements 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 10 of Regulation S-X of the Securities and Exchange Commission (“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 the Partnership's audited financial statements and notes thereto included in the Partnership's 2010 Form 10-K. The Partnership's accounting policies are described in the Notes to Financial Statements in the Partnership's 2010 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three and six months ended June 30, 2011, and the cash flows for the same periods, 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 correct the prior period disclosures to conform to the current year presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership's previously reported financial position, cash flows, net income or partners' equity. See Note 4, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership's natural gas and crude oil derivative instruments.


Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for the Partnership's financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on the Partnership's financial statements.

-5-

ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)


Recently Issued Accounting Standards

Fair Value Measurement

On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") (collectively the "Boards") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes also require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on the Partnership's financial statements.

Note 3−Transactions with Managing General Partner and Affiliates

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership's portion of unexpired derivative instruments is recorded on the condensed balance sheets under the captions “Due from Managing General Partner-derivatives,” in the case of net unrealized gains or “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 (to) Managing General Partner-other, net,” which remain undistributed or unsettled with the Partnership's investors as of the dates indicated.

    
 
June 30, 2011
 
December 31, 2010
Natural gas, NGLs and crude oil sales revenues
collected from the Partnership's third-party customers
$
724,204

 
$
875,468

Commodity price risk management, realized gain
125,148

 
478,306

Other (1)
(475,849
)
 
(819,659
)
Total Due from Managing General Partner-other, net
$
373,503

 
$
534,115


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


-6-

ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

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 and its affiliates for the three and six months ended June 30, 2011 and 2010. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.    

 
 Three months ended June 30,
 
Six months ended June 30,
 
2011
 
2010
 
2011
 
2010
 Well operations and maintenance
$
753,032

 
$
1,269,056

 
$
2,012,583

 
$
1,970,989

 Gathering, compression and processing fees
102,679

 
133,362

 
203,249

 
282,185

 Direct costs - general and administrative
39,796

 
44,447

 
87,046

 
81,975

 Cash distributions
543,917

 
1,563,999

 
1,232,049

 
3,778,234



Note 4−Fair Value Measurements and Disclosures

Derivative Financial Instruments

Determination of fair value. Fair value accounting standards have established a fair value hierarchy that prioritizes the inputs used in applying a valuation methodology. 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. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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 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) in active markets for identical assets or liabilities.

Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) 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 for the asset or liability.

Derivative Financial Instruments. The Partnership measures the fair value of its 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 and crude oil forward curves, 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 counterparties to the Partnership's derivative instruments are primarily financial institutions. The Managing General Partner validates the fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the 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.

-7-

ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)


The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, both current and non-current portions, measured at fair value on a recurring basis.
 
June 30, 2011
 
December 31, 2010 (a)
 
 Level 2 (b)
 
 Level 3 (c)
 
 Total
 
 Level 2 (b)
 
 Level 3 (c)
 
 Total
 
 
 
 
 
 
 
 
 
 
 
 
 Assets:
 
 
 
 
 
 
 
 
 
 
 
 Commodity based derivatives
$
6,946,626

 
$
111,519

 
$
7,058,145

 
$
7,511,512

 
$
355,842

 
$
7,867,354

 Total assets
6,946,626

 
111,519

 
7,058,145

 
7,511,512

 
355,842

 
7,867,354

 
 
 
 
 
 
 
 
 
 
 
 
 Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 Commodity based derivatives
(350,280
)
 

 
(350,280
)
 
(618,004
)
 

 
(618,004
)
 Basis protection derivative contracts
(4,945,433
)
 

 
(4,945,433
)
 
(5,519,730
)
 

 
(5,519,730
)
 Total liabilities
(5,295,713
)
 

 
(5,295,713
)
 
(6,137,734
)
 

 
(6,137,734
)
 Net asset
$
1,650,913

 
$
111,519

 
$
1,762,432

 
$
1,373,778

 
$
355,842

 
$
1,729,620


(a) The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by $7.5 million) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by $6.1 million). The amounts presented reflect these reclassifications and conform to current period presentation.
(b) Includes the Partnership's fixed-price swaps and basis swaps.
(c) Includes the Partnership's natural gas collars.
The following table presents a reconciliation of the Partnership's Level 3 fair value measurements.
 
Six months ended
 
June 30, 2011
 
June 30, 2010 (1)
 Fair value, net asset, beginning of period
$
355,842

 
$
739,017

 Changes in fair value included in statement of operations line item:
 
 
 
 Commodity price risk management, net
53,955

 
360,591

 Settlements
(298,278
)
 
(743,756
)
 Fair value, net asset, end of period
$
111,519

 
$
355,852

 
 
 
 
Change in unrealized gain (loss) relating to assets (liabilities) still held as of
 

 
 
June 30, 2011 and 2010, respectively, included in statement of operations line item:
 
 
 
 Commodity price risk management, net
$
11,362

 
$
287,647


(1) The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by $5.3 million). The amounts presented reflect these reclassifications and conform to current period presentation.
See Note 5, Derivative Financial Instruments, for additional disclosure related to the Partnership's derivative financial instruments.

Non-Derivative Financial Assets and Liabilities

The carrying values of the financial instruments comprising 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, 2011
(unaudited)


Note 5−Derivative Financial Instruments
As of June 30, 2011, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 3,426,972 MMbtu of natural gas and 13,906 Bbl of crude oil.

The following table presents the location and fair value amounts of the Partnership's derivative instruments on the accompanying condensed balance sheets. These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.
 
 
 
 
 
Fair Value
 
 
 
 
 
June 30,
 
December 31,
Derivative instruments not designated as hedge(1):
 
Balance Sheet Line Item
 
2011
 
2010
Derivative Assets:
Current
 
 
 
 
 
 
 
Commodity contracts
 
Due from Managing General Partner-derivatives
 
$
3,330,864

 
$
3,178,313

 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
Due from Managing General Partner-derivatives
 
3,727,281

 
4,689,041

Total Derivative Assets
 
 
 
 
$
7,058,145

 
$
7,867,354

 
 
 
 
 
 
 
 
Derivative Liabilities:
Current
 
 
 
 

 
 

 
Commodity contracts
 
Due to Managing General Partner-derivatives
 
$
350,280

 
$
618,004

 
Basis protection contracts
 
Due to Managing General Partner-derivatives
 
2,260,647

 
1,962,839

 
Non Current
 
 
 
 
 
 
 
Basis protection contracts
 
Due to Managing General Partner-derivatives
 
2,684,786

 
3,556,891

Total Derivative Liabilities
 
 
 
$
5,295,713

 
$
6,137,734


(1)As of June 30, 2011 and December 31, 2010, none of the Partnership's derivative instruments were designated as hedges.


-9-

ROCKIES REGION 2007 LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(unaudited)

The following tables presents the impact of the Partnership's derivative instruments on the Partnership's accompanying condensed statements of operations.
 
 
 Three months ended June 30,
 
 
2011
 
2010
Statement of operations line item:
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains 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
 
$
153,671

 
$
6,350

 
$
160,021

 
$
305,112

 
$
99,001

 
$
404,113

Unrealized gains (losses)
 
(153,671
)
 
790,613

 
636,942

 
(305,112
)
 
1,349,530

 
1,044,418

Total commodity price risk management gain, net
$

 
$
796,963

 
$
796,963

 
$

 
$
1,448,531

 
$
1,448,531

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six months ended June 30,
 
 
2011
 
2010
Statement of operations line item:
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains (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)
 
$
399,991

 
$
(43,169
)
 
$
356,822

 
$
1,326,994

 
$
1,032,050

 
$
2,359,044

Unrealized gains (losses)
 
(399,991
)
 
432,803

 
32,812

 
(1,326,994
)
 
4,889,770

 
3,562,776

Total commodity price risk management gain, net
$

 
$
389,634

 
$
389,634

 
$

 
$
5,921,820

 
$
5,921,820


Concentration of Credit Risk. The Managing General Partner makes extensive use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner's credit facility agreement, as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of the Partnership's derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on this evaluation, the Managing General Partner has determined that the impact of the nonperformance of the counterparties on the fair value of the Partnership's derivative instruments was not significant.

Note 6−Commitments and Contingencies

Legal Proceedings

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


-10-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


Environmental

Due to the nature of the natural gas and crude oil industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to avoid environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership's environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. During the six months ended June 30, 2011, there were no new environmental remediation projects identified by the Managing General Partner for the Partnership. As of June 30, 2011 and December 31, 2010, the Partnership had accrued environmental remediation liabilities for the Partnership's Grand Valley Field in the amount of $5,000 for each date, which is included in line item captioned “Accounts payable and accrued expenses” on the condensed Balance Sheets. The Managing General Partner is not currently aware of any environmental claims existing as of June 30, 2011, which have not been provided for or would otherwise have a material impact on the 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 the Partnership's properties.

Note 7−Third-party Settlements

Under the Partnership's revenue recognition policy, natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. In accordance with this policy, the Partnership recorded a net reduction in natural gas revenues of approximately $52,000 for the six months ended June 30, 2011 for the following settlements:

(1) During the quarter ended March 31, 2011, the Partnership recorded approximately $154,000 in natural gas revenues which was the result of the receipts from a settlement from a third-party gas purchaser relating to prior years' volume imbalances. The settlement was recorded in the quarter ended March 31, 2011, as this was the period that the revenues were determinable and collection was reasonably assured.

(2) During the quarter ended June 30, 2011, the Partnership reduced natural gas revenues by approximately $206,000 which was the result of a settlement with the same third-party gas purchaser relating to pricing on prior year cash received for natural gas sales.

-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 natural gas, NGLs and crude oil. The Partnership began natural gas and crude oil operations in 2007 and operates 97 gross (95.9 net) productive wells located in the Rocky Mountain Region in the state of Colorado. In addition, two gross (2.0 net) Wattenberg Field Partnership wells are temporarily not in production at June 30, 2011 due to operational problems. The Managing General Partner markets the Partnership's natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities or oil companies, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces. PDC does not charge an additional fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or 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 and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.
Recent Developments
PDC Sponsored Drilling Program Acquisition Plan
PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, which began in the fall of 2010 and extends through 2012, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of the particular partnership other than those held by PDC or its affiliates (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership. For additional information regarding PDC's intention to pursue acquisitions of PDC sponsored partnerships, refer to prior disclosure included in PDC's filings made with the SEC. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement does or will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnership units held by the non-affiliated investor partners of each respective limited partnership. Consummation of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and each non-affiliated investor partner will receive the right to receive a cash payment for their limited partnership units in that partnership and will no longer participate in that partnership's future earnings or any further economic benefit.
In June 2011, PDC acquired three affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership. PDC purchased these partnerships for the aggregate amount of $43.0 million.
In June 2011, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership, PDC 2003-D Limited Partnership and the PDC 2002-D Limited Partnership (collectively, the “2003 and 2002-D Partnerships”). PDC serves as the Managing General Partner of each of the 2003 and 2002-D Partnerships. Pursuant to each merger agreement, if the merger is approved by the holders of a majority of the limited partnership units held by the non-affiliated investor partners of each respective partnership, as well as the satisfaction of other customary closing conditions, then the partnership will merge with and into a wholly-owned subsidiary of PDC. Upon clearance by the SEC, a definitive proxy statement will be mailed to the non-affiliated investor partners of each of the 2003 and 2002-D Partnerships requesting their approval of the merger transactions. Although there is no assurance of the likelihood or timing of the completion of the SEC proxy disclosure review process, the special meetings whereby non-affiliated investor partners of the 2003 and 2002-D Partnerships will have an opportunity to vote and approve the respective merger agreements are currently expected to occur in the fourth quarter of 2011.
The feasibility and timing of any future cash purchase offer by PDC to any additional partnership, including this Partnership, depends on that partnership's suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership's well inventory; favorability of economics for Wattenberg Field well refracturing or recompletion; and SEC reporting compliance status and timing associated with gaining all necessary regulatory approvals required for a merger and repurchase offer. There is no assurance that any merger and acquisition will occur, as a result of PDC's proposed repurchase offers to the 2003 and 2002-D Partnerships, or any potential proposed repurchase offer to any other of PDC's various public limited partnerships, including this Partnership, should they occur.

-12-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


Additional Codell Formation Development Plan
The Managing General Partner has prepared a plan for the Partnership's Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “Additional Codell Formation Development Plan”). The Additional Codell Formation Development Plan consists of the Partnership's refracturing of wells currently producing in the Codell formation and the recompletion of wells, currently producing in the deeper J-Sand formation, in the shallower Codell formation production zone. Under the Additional Codell Formation Development Plan, the Partnership plans to initiate additional development activities during 2012. Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, while recompletion activities consist of an initial hydraulic fracturing treatment in a new production zone, all within an existing well bore.
Additional Codell formation development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ten years after initial well drilling so that well resources are optimally utilized. This additional Codell formation development would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to refracture or recomplete the individual wells and to determine the timing of any additional Codell formation development activity. The timing of the refracturing or recompletion can be affected by the desire to optimize the economic return by additional development of the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership. On average, the production resulting from PDC's Codell refracturings or recompletions have been at modeled economics; however, all refracturings or recompletions have not been economically successful and similar future refracturing or recompletion activities may not be economically successful. If the additional Codell formation development work is performed, PDC will charge the Partnership for the direct costs of refracturing or recompletion, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from cash available for distributions. The Managing General Partner considers the cash available for distributions to be the Partnership's net cash flows provided by operating activities less any net cash used in capital activities.
The Limited Partnership Agreement (the “Agreement”) permits the Partnership to borrow funds or receive advances, from the Managing General Partner, its affiliates or unaffiliated persons, for Partnership activities. At this time, the Managing General Partner does not anticipate electing to fund the initial Additional Codell Formation Development Plan well refracturings or recompletions, nor any subsequent refracturings or recompletions, through bank borrowing. In the event that the Partnership's Codell formation refracturing or recompletion activities are funded in part through borrowing, potential cash available for distributions derived from production increases provided by the further development of the Partnership's Wattenberg Field wells may not be sufficient to repay the Partnership's borrowing financial obligations, which will include principal and interest. Borrowings, if any, will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for loan repayment. However, any bank borrowings may be collateralized by the Partnership's assets.
During the fourth quarter 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing or recompletion costs. This program will materially reduce, up to 100%, cash available for distributions of the partnerships for a period of time not to exceed five years.
Current estimated costs for these well refracturings or recompletions are between $175,000 and $240,000 per activity. As of June 30, 2011, this Partnership had scheduled to complete 77 additional Codell formation development opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $13.5 million and $18.5 million. The Managing General Partner will continually evaluate the timing of commencing these additional Codell formation development activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development. During the three months ended June 30, 2011, $200,000 was withheld from the Partnership's cash distributions pursuant to the Additional Codell Development Plan. Cumulatively, $920,000 has been withheld from Partnership distributions through July 31, 2011 and resides in the Partnership's bank account.
If any or all of the Partnership's Wattenberg wells are not refractured or recompleted, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number and timing of the additional Codell formation development activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing and recompletion costs and projected cash withholding, all scheduled Partnership additional Codell formation development activity will be completed within a five year period. Any funds not used for refracturing, recompletion or other operational needs will be distributed to the Managing General Partner and Investor Partners based on their proportional ownership interest.

-13-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)



Implementation of the Additional Codell Formation Development Plan has and will continue to reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership funds. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliated investor partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Additional Codell Formation Development Plan. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated investor partners should depend upon the advice of their own tax advisors concerning the effects of the Additional Codell Formation Development Plan.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 30% or $2.5 million for the first six months of 2011 compared to the first six months of 2010, while sales volumes declined 28% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.11 for the current year period compared to $5.26 for the same period a year ago. Realized derivative gains from natural gas and crude oil sales contributed an additional $0.32 per Mcfe or $0.4 million to the first six months of 2011 total revenues compared to an additional $1.50 or $2.4 million to the first six months of 2010. Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $5.43 for the current year six months from $6.76 for the same prior year period.


 

-14-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)



Results of Operations

Summary Operating Results

The following table presents selected information regarding the Partnership’s results of operations.
 
 Three months ended June 30,
 
Six months ended June 30,
 
2011
 
2010
 
 Change
 
2011
 
2010
 
Change
Number of producing wells (end of period)
97

 
99

 
(2
)
 
97

 
99

 
(2
)
 
 
 
 
 
 
 
 
 
 
 
 
Production(1)
 
 
 
 
 
 
 

 
 
 
 

Natural gas (Mcf)(2)
430,895

 
577,346

 
(25
)%
 
891,053

 
1,202,668

 
(26
)%
NGLs (Bbl)
4,521

 
7,794

 
(42
)%
 
10,007

 
17,485

 
(43
)%
Crude oil (Bbl)
12,573

 
21,233

 
(41
)%
 
29,878

 
43,623

 
(32
)%
Natural gas equivalents (Mcfe)(3)
533,459

 
751,508

 
(29
)%
 
1,130,363

 
1,569,316

 
(28
)%
Average Mcfe per day
5,862

 
8,258

 
(29
)%
 
6,245

 
8,670

 
(28
)%
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas, NGLs and Crude Oil Sales
 
 
 
 
 
 
 

 
 

 
 

Natural gas (4) (5)
$
1,224,583

 
$
1,675,752

 
(27
)%
 
$
2,803,835

 
$
4,693,573

 
(40
)%
NGLs
118,291

 
168,314

 
(30
)%
 
300,432

 
433,393

 
(31
)%
Crude oil
1,183,214

 
1,508,118

 
(22
)%
 
2,676,537

 
3,127,377

 
(14
)%
Total natural gas, NGLs and crude oil sales
$
2,526,088

 
$
3,352,184

 
(25
)%
 
$
5,780,804

 
$
8,254,343

 
(30
)%
 
 
 
 
 
 
 
 
 
 
 
 
Realized Gain (Loss) on Derivatives, net
 
 
 
 
 
 
 

 
 

 
 

Natural gas
$
383,720

 
$
53,928

 
*

 
$
746,419

 
$
1,680,915

 
(56
)%
Crude oil
(223,699
)
 
350,185

 
(164
)%
 
(389,597
)
 
678,129

 
(157
)%
Total realized gain on derivatives, net
$
160,021

 
$
404,113

 
(60
)%
 
$
356,822

 
$
2,359,044

 
(85
)%
 
 
 
 
 
 
 
 
 
 
 
 
Average Selling Price (excluding realized gain (loss) on derivatives)
 
 
 
 
 
 
 

 
 

 
 

Natural gas (per Mcf)(6)
$
2.84

 
$
2.90

 
(2
)%
 
$
3.15

 
$
3.90

 
(19
)%
NGLs (per Bbl)
26.16

 
21.60

 
21
 %
 
30.02

 
24.79

 
21
 %
Crude oil (per Bbl)
94.11

 
71.03

 
32
 %
 
89.58

 
71.69

 
25
 %
Natural gas equivalents (per Mcfe)
4.74

 
4.46

 
6
 %
 
5.11

 
5.26

 
(3
)%
 
 
 
 
 
 
 
 
 
 
 
 
Average Selling Price (including realized gain (loss) on derivatives)
 
 
 
 
 
 
 

 
 

 
 

Natural gas (per Mcf)
$
3.73

 
$
3.00

 
25
 %
 
$
3.98

 
$
5.30

 
(25
)%
NGLs (per Bbl)
26.16

 
21.60

 
21
 %
 
30.02

 
24.79

 
21
 %
Crude oil (per Bbl)
76.32

 
87.52

 
(13
)%
 
76.54

 
87.24

 
(12
)%
Natural gas equivalents (per Mcfe)
5.04

 
5.00

 
1
 %
 
5.43

 
6.76

 
(20
)%
 
 
 
 
 
 
 
 
 
 
 
 
Average cost per Mcfe
 
 
 
 
 
 
 
 
 
 
 
Natural gas, NGLs and crude oil production cost(7)
$
1.89

 
$
2.16

 
(12
)%
 
$
2.21

 
$
1.60

 
38
 %
Depreciation, depletion and amortization
$
2.33

 
$
3.17

 
(26
)%
 
$
2.43

 
$
3.17

 
(23
)%
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs and expenses:
 
 
 
 
 
 
 

 
 

 
 

Direct costs - general and administrative
$
39,796

 
$
44,447

 
(10
)%
 
$
87,046

 
$
81,975

 
6
 %
Depreciation, depletion and amortization
$
1,242,257

 
$
2,379,771

 
(48
)%
 
$
2,745,071

 
$
4,973,089

 
(45
)%
 
 
 
 
 
 
 
 
 
 
 
 
Cash distributions
$
1,470,045

 
$
4,227,025

 
(65
)%
 
$
3,329,861

 
$
10,211,444

 
(67
)%
*Percentage change not meaningful, equal to or greater than 250% or not calculable.
Amounts may not calculate due to rounding.

-15-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


  
_______________
(1) Production is net and determined by multiplying the gross production volume of properties in which the Partnership has an interest by the average percentage of the leasehold or other property interest the Partnership owns.
(2) Approximately 19,073 Mcf, or 2%, of the Partnership's natural gas production was the result of a settlement with a third-party gas purchaser recorded during the six months ended June 30, 2011, related to prior years' volume imbalances.
(3) Six Mcf of natural gas equals one Bbl of crude oil or NGL.
(4) Approximately $154,000, or 6%, of the Partnership's natural gas sales and with an effect of $0.11 per Mcf to the Partnership's average overall Mcf price for natural gas sales revenue for the six months ended June 30, 2011 was the result of the settlement with a third-party gas purchaser noted in footnote 2 above.
(5) A reduction in natural gas revenue of approximately $206,000, or 17% and with an effect of $0.48 per Mcf price for natural gas sales revenue was recognized for the three months ending June 30, 2011 for a pricing settlement for prior periods with a third party gas purchaser. This reduction was 7% of sales and with an effect of $0.23 per Mcf price for natural gas sales revenue for the six months ended June 30, 2011.
(6) The Partnership's average sales price for natural gas is based on the "net-back" method of accounting for transportation, gathering and processing arrangements with natural gas purchasers. See the Partnership's revenue recognition policy described in Note 2, Summary of Significant Accounting Policies, to financial statements in the Partnership's 2010 Form 10-K and Part 1, Item 2, Financial Condition, Liquidity and Capital Resources - Cash Flows, included in this report.
(7) Production costs represent natural gas, NGLs and crude oil operating expenses which include production taxes.


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

Bbl – One barrel or 42 U.S. gallons liquid volume
MBbl – One thousand barrels
Mcf – One thousand cubic feet
MMcf – One million cubic feet
Mcfe – One thousand cubic feet of natural gas equivalents
MMcfe – One million cubic feet of natural gas equivalents
MMbtu – One million British Thermal Units
 

Natural Gas, NGLs and Crude Oil Sales

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

For the six months ended June 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 28%. Excluding the natural gas settlement identified in footnotes 2 and 4 of the Summary Operating Results table, natural gas, NGLs, and crude oil production, on an energy equivalency-basis, decreased 29% due to normal production declines for this stage in the wells' production life cycle.
The $2.5 million, or 30% decrease in sales for the 2011 six month period as compared to the prior year period, was primarily a reflection of sales volume decreases of 28% and a decline in sales prices of 3%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.11 for the current year six month period compared to $5.26 for the same period a year ago.
Natural gas, NGLs and crude oil revenues decreased by 40%, 31% and 14% respectively. The Partnership's natural gas revenue decrease resulted from lower Partnership natural gas production volumes of 26% and from decreased commodity prices of 19%, including the settlements identified in footnotes 2, 4 and 5 of the Summary Operating Results table. The decrease in NGLs revenue was due to a decrease of 43% in NGLs production volumes, partially offset by increased commodity prices per Bbl of 21%. The crude oil revenue decrease is due primarily to sales volume decreases of 32%, partially offset by the rise in commodity prices per Bbl of 25% during the current six month period.

-16-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


Three months ended June 30, 2011 as compared to three months ended June 30, 2010

For the three months ended June 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 29% due to normal production declines for this stage in the wells' production life cycle.

The $0.8 million, or 25%, decrease in sales for the 2011 three month period as compared to the prior year period was primarily a reflection of sales volume decreases of 29% partially offset by an increase in sales prices of 6%, including the settlement identified in footnote 5 of the Summary Operating Results table. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $4.74 for the current year three month period compared to $4.46 for the same period a year ago.

Natural gas, NGLs and crude oil revenues decreased by 27%, 30% and 22%, respectively. The Partnership's natural gas revenue decrease resulted from lower Partnership natural gas production volumes of 25%, and decreased commodity prices per Mcf of 2%, including the settlement identified in footnote 5 of the Summary Operating Results table. The decrease in NGLs revenue was due to a decrease of 42% in NGLs production volumes, partially offset by increased commodity prices per Bbl of 21%. The crude oil revenue decrease is due primarily to sales volume decreases of 41%, partially offset by the rise in commodity prices per Bbl of 32% during the current three month period.

Commodity Price Risk Management, Net

The Partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices. The Partnership has in place a variety of collars, fixed-price swaps and basis swaps on a portion of the Partnership's estimated natural gas and crude oil production. The Partnership sells its natural gas and crude oil at similar prices to the indices inherent in the Partnership's derivative instruments. As a result, for the volumes underlying the Partnership's derivative positions, the Partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the Partnership's commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps.

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

The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management, net.
 
Three months ended June 30,
 
Six months ended June 30,
 
2011
 
2010
 
2011
 
2010
Commodity price risk management gain, net:
 
 
 
 
 
 
 
  Realized gains (losses)
 
 
 
 
 
 
 
  Natural gas
$
383,720

 
$
53,928

 
$
746,419

 
$
1,680,915

  Crude oil
(223,699
)
 
350,185

 
(389,597
)
 
678,129

       Total realized gains, net
160,021

 
404,113

 
356,822

 
2,359,044

 
 
 
 
 
 
 
 
  Unrealized gains (losses)
 
 
 
 
 
 
 
Reclassification of realized gains included in
 
 
 
 
 
 
 
   prior periods unrealized
(153,671
)
 
(305,112
)
 
(399,991
)
 
(1,326,994
)
  Unrealized gains for the period
790,613

 
1,349,530

 
432,803

 
4,889,770

       Total unrealized gains, net
636,942

 
1,044,418

 
32,812

 
3,562,776

Total commodity price risk management gain, net
$
796,963

 
$
1,448,531

 
$
389,634

 
$
5,921,820



-17-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Realized gains recognized in the six months ended June 30, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $1.7 million for the six months ended June 30, 2011. These gains were offset in part by an approximate $1.0 million loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and Colorado Interstate Gas (“CIG”) was narrower than the strike price of the basis positions. The Partnership also realized an approximate $0.4 million loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the six months ended June 30, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shifts downward in the natural gas curves resulted in an unrealized gain of approximately $0.8 million which was partially offset by unrealized losses of approximately $0.4 million on the Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow.
The realized derivative gains for the 2010 six month period were approximately $2.4 million. These realized gains were primarily a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the six month period, realized gains related to natural gas and oil derivatives were approximately $2.3 million and $0.7 million, respectively, and realized losses on the Partnership's CIG basis protection swaps were approximately $0.6 million. Unrealized gains for the six month period, were approximately $4.9 million due primarily to a downward shift in the natural gas and oil forward curves. Unrealized gains on the Partnership's natural gas and oil positions for the period were approximately $4.4 million and $0.5 million, respectively.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

Realized gains recognized in the three months ended June 30, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $1.0 million for the three months ended June 30, 2011. These gains were offset in part by an approximate $0.6 million loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and CIG was narrower than the strike price of the basis positions. The Partnership also realized an approximate $0.2 million loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the three months ended June 30, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The significant shift downward in the crude oil curve resulted in an unrealized gain of approximately $0.1 million during the three months ended June 30, 2011. Likewise, the shifts downward in the natural gas curves resulted in a total unrealized gain of approximately $0.8 million. These unrealized gains were partially offset by unrealized losses of approximately $0.1 million on the Partnership's CIG basis protection swaps due to the narrowing of the NYMEX-CIG basis differential.
The realized derivative gains for the 2010 second quarter were approximately $0.4 million. These realized gains are a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the quarter, realized gains related to natural gas and oil derivatives were approximately $1.0 million and were offset by realized losses on the Partnership's CIG basis swaps of $0.6 million. For the 2010 second quarter, the unrealized gains were primarily related to the oil positions, as the forward strip price shifted downward during the quarter, and the widening of the NYMEX-CIG basis differential. Unrealized gains on the Partnership's oil positions and CIG basis swaps for the 2010 second quarter were approximately $0.6 million and $0.7 million, respectively.



-18-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


The following table presents the Partnership's derivative positions in effect as of June 30, 2011.
 
Collars
 
Fixed-Price Swaps
 
CIG Basis Protection Swaps
 
 
Commodity/
Index
Quantity
(Gas-MMBtu(1))
 
Weighted Average
Contract Price
 
Quantity
(Gas-MMBtu(1)
Oil-Bbls)
 
Weighted
Average
Contract
Price
 
Quantity
(Gas-MMBtu(1))
 
Weighted
Average
Contract
Price
 

Fair Value at
June 30, 2011(2)
Floors
 
Ceilings
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
07/01 - 09/30/2011

 
$

 
$

 
401,561

 
$
6.73

 
401,561

 
$
(1.88
)
 
$
327,941

10/01 - 12/31/2011

 

 

 
384,547

 
6.78

 
384,547

 
(1.88
)
 
250,305

01/01 - 03/31/2012
28,713

 
6.00

 
8.27

 
337,506

 
6.98

 
366,219

 
(1.88
)
 
203,808

04/01 - 06/30/2012
15,280

 
6.00

 
8.27

 
339,409

 
6.98

 
354,689

 
(1.88
)
 
288,162

07/01 - 12/31/2012
42,337

 
6.00

 
8.27

 
639,037

 
6.98

 
681,374

 
(1.88
)
 
392,366

2013

 

 

 
1,238,582

 
7.12

 
1,238,582

 
(1.88
)
 
650,130

Total Natural Gas
86,330

 
 
 
 
 
3,340,642

 
 
 
3,426,972

 
 
 
2,112,712

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude Oil
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
07/01 - 09/30/2011

 

 

 
6,977

 
70.75

 

 

 
(170,800
)
10/01 - 12/31/2011

 

 

 
6,929

 
70.75

 

 

 
(179,480
)
Total Crude Oil

 
 
 
 
 
13,906

 
 
 

 
 
 
(350,280
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Natural Gas and Crude Oil
 
 
 
 
 
 
 
 
 
 
 
 
$
1,762,432


(1) A standard unit of measure for natural gas (one MMBtu equals one Mcf).
(2) Approximately 2% of the fair value of the Partnership's derivative assets and none of the Partnership's derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 4, Fair Value of Financial Instruments, to the accompanying unaudited condensed financial statements included in this report.


Natural Gas, NGLs and Crude Oil Production Costs

Generally, natural gas, NGLs and crude oil production costs vary with changes in total natural gas, NGLs and crude oil 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 natural gas, NGLs and crude oil sales. Transportation costs vary directly with 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, 2011 as compared to six months ended June 30, 2010

Production and operating costs per Mcfe increased to $2.21 during the current period compared to $1.60 for the prior year period due to the effect of higher per-well related expenditures, partially offset by lower per-volume related natural gas, NGLs and crude oil production costs. Current period production and operating costs included approximately $0.6 million in tubing repairs at four of the Partnership's Grand Valley Field wells in comparison to approximately $0.5 million for tubing repairs performed at two of the Partnership's wells in 2010.


-19-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


Three months ended June 30, 2011 as compared to three months ended June 30, 2010
Production and operating costs per Mcfe decreased to $1.89 during the current period compared to $2.16 for the prior year period due to the effect of lower per-well related expenditures, partially offset by lower per-volume related natural gas, NGLs and crude oil production costs. Current period production and operating costs decreased by approximately $0.7 million, primarily due to workovers and tubing repair projects at two of the Partnership's Grand Valley Field wells performed in 2010 accompanied by decreases in natural gas transportation and lease operating expenses resulting from decreased production volumes as compared to the same period in 2010.
Direct Costs−General and Administrative
Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Direct costs - general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer's reserve reports and legal matters. Direct costs remained relatively consistent during the six months ended June 30, 2011, compared to the same period in 2010.
Three months ended June 30, 2011 as compared to three months ended June 30, 2010
Direct costs - general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer's reserve reports and legal matters. Direct costs remained relatively consistent during the three months ended June 30, 2011, compared to the same period in 2010.
Depreciation, Depletion and Amortization
Six months ended June 30, 2011 as compared to six months ended June 30, 2010
The DD&A expense rate per Mcfe decreased to $2.43 for the 2011 six month period, compared to $3.17 during the same period in 2010. The decrease of $0.74 in the per Mcfe rates for the 2011 period compared to the 2010 period is primarily due to a decrease of $1.26 as result of the 2010 impairment of the Partnership's Grand Valley Field. This decrease was partially offset by a net increase of $0.52 resulting from a downward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves in the Grand Valley Field partially offset by the upward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves in the Wattenberg Field as of December 31, 2010. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of approximately $2.2 million for the 2011 six month period compared to the same 2010 period.
Three months ended June 30, 2011 as compared to three months ended June 30, 2010
The DD&A expense rate per Mcfe decreased to $2.33 for the 2011 three month period, compared to $3.17 during the same period in 2010. The decrease of $0.84 in the per Mcfe rates for the 2011 period compared to the 2010 period is primarily due to a decrease of $1.31 as a result of of the 2010 impairment of the Partnership's Grand Valley Field. This decrease was partially offset by a net increase of $0.47 resulting from downward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves in the Grand Valley Field partially offset by the upward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves in the Wattenberg Field as of December 31, 2010. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of approximately $1.1 million for the 2011 three month period compared to the same 2010 period.

Financial Condition, Liquidity and Capital Resources
The Partnership's primary sources of cash for the six months ended June 30, 2011 were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the realized gains from the Partnership's derivative positions. These sources of cash were primarily used to fund the Partnership's operating costs, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner. During the quarter ended June 30, 2011, the Managing General Partner withheld $200,000 from the Partnership's cash distributions pursuant to the Additional Codell Development Plan. Through July 31, 2011, $920,000 has been withheld from Partnership distributions to fund this plan. These and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing or recompletion costs to be incurred during 2012. For additional information, see Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments-Additional Codell Development Plan.


-20-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)



Fluctuations in the Partnership's operating cash flows are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership's cash flow from operations becomes the net activity between the Partnership's natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership's expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of June 30, 2011, the Partnership had natural gas and crude oil derivative positions in place covering 87% of the expected natural gas production and 45% of expected crude oil production for the remainder of 2011, at an average price of $4.87 per Mcf and $70.75 per Bbl, respectively. The Partnership's current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the first quarter of 2010 comparative period which were the result of contracts entered into during the high 2008 commodity price market. 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 the Partnership's revenues.

The Partnership's future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains. Natural gas, NGLs and crude oil production from the Partnership's existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, lower revenues. The 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 negative impact on the Partnership's operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2011 and beyond, and may substantially reduce or restrict the Partnership's ability to participate in the additional Codell formation development activities which are more fully described in Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Additional Codell Formation Development Plan.

Although the Agreement permits the Partnership to borrow funds on its behalf for Partnership activities, the Managing General Partner does not anticipate electing to fund through bank borrowings, any portion of the Partnership's refracturing and recompletion activities. These refracturings and recompletions are scheduled to begin in 2012. Partnership borrowings, should any occur, will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for repaying the loan.

Working Capital

The Partnership had working capital of approximately $3.2 million at June 30, 2011 compared to working capital of $2.9 million at December 31, 2010, an increase of approximately $0.3 million. This increase was primarily due to the following changes:

Cash and cash equivalents increased by $0.6 million between June 30, 2011 and December 31, 2010.
Accounts receivable decreased by $0.5 million between June 30, 2011 and December 31, 2010.
Realized and unrealized derivative gains receivable decreased by $0.2 million between June 30, 2011 and December 31, 2010.
Due to the Managing General Partner, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, decreased by $0.3 million between June 30, 2011 and December 31, 2010.
Oil inventory increased by $0.1 million between June 30, 2011 and December 31, 2010.

Working capital is expected to fluctuate by increasing during periods of Additional Codell Formation Development Plan funding and by decreasing during periods when payments are made for refracturing or recompletions.


-21-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


Cash Flows

Cash Flows From Operating Activities

The Partnership's cash flows provided by operating activities are primarily impacted by commodity prices, production volumes, realized gains and losses from its derivative positions, operating costs and general and administrative expenses. See Results of Operations above for an additional discussion of the key drivers of cash flows provided by operating activities.

Natural gas, NGLs and crude oil prices exhibit a high degree of volatility. These price variations have a material impact on the Partnership's financial results. Natural gas and NGLs prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets has resulted in local market oversupply situations from time to time. Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond the Partnership's control. Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a market basket of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices. The CIG Index and other indices for production delivered to other Rocky Mountain pipelines have historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential of CIG relative to NYMEX averaged $0.31 and $0.32 for the six months ended June 30, 2011 and 2010, respectively.

The price the Partnership receives on its natural gas sales is impacted by the Managing General Partner's transportation, gathering and processing agreements. The Partnership currently uses the "net-back" method of accounting for these arrangements related to the Partnership's natural gas sales. The Partnership sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since 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.

Net cash provided by operating activities was approximately $4.0 million for the six months ended June 30, 2011, compared to approximately $10.3 million for the comparable period in 2010. The approximately $6.3 million decrease in cash provided by operating activities was due primarily to the following:

A decrease in natural gas, NGLs and crude oil sales receipts of $2.9 million, or 31%,

A decrease in commodity price risk management realized gains receipts of $3.0 million, or 81%,
An increase in production costs and direct costs - general and administrative payments of $0.4 million.

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts totaled approximately $28,000 and $81,000 for the six months ended June 30, 2011 and 2010, respectively.


-22-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in May 2008 and has distributed $80.3 million through June 30, 2011. The table below presents cash distributions to the Partnership's investors. Managing General Partner distributions include amounts distributed to PDC for its Managing General Partner's 37% ownership share in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 63% ownership share in the Partnership.
Distributions
 
 
 
 
 
 
 
Three months ended June 30,
 
Managing General Partner
 
Investor Partners
 
Total
2011
 
$
543,917

 
$
926,128

 
$
1,470,045

2010
 
$
1,563,999

 
$
2,663,026

 
$
4,227,025

 
 
 
 
 
 
 
Six months ended June 30,
 
Managing General Partner
 
Investor Partners
 
Total
2011
 
$
1,232,049

 
$
2,097,812

 
$
3,329,861

2010
 
$
3,778,234

 
$
6,433,210

 
$
10,211,444


The decrease in total distributions for 2011 as compared to 2010 is primarily due to the significant decrease in cash flows from operating activities during 2011 and from funds held by the Managing General Partner for the Additional Codell Formation Development Plan. The Partnership began funding for the Additional Codell Development Plan during October 2010. During the quarter ended June 30, 2011, on a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $74,000 and $126,000 from the Managing General Partner and Investor Partners' share of cash available for distributions, respectively.

Off-Balance Sheet Arrangements

As of June 30, 2011, the 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 the Partnership's financial condition, revenues or expenses, 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 in this report.

Recent Accounting Standards

See Note 2, Recent Accounting Standards, to the accompanying unaudited condensed financial statements, included 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 the 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 the Partnership's 2010 Form 10-K.

-23-

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

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

(a)    Evaluation of Disclosure Controls and Procedures

As of June 30, 2011, PDC, as Managing General Partner on behalf of the 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 the 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 the 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 the 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 the Partnership's disclosure controls and procedures were effective as of June 30, 2011.

(b)    Changes in Internal Control over Financial Reporting
 
During the three months ended June 30, 2011, PDC, the Managing General Partner, made no changes in the 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 the Partnership's internal control over financial reporting.

-24-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)


PART II – OTHER INFORMATION

Item 1.    Legal Proceedings

Neither the Partnership nor PDC, in its capacity as the Managing General Partner of the Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the 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 May 2011, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the 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.

There were no negotiated-basis limited partnership units repurchased by PDC for the three months ended June 30, 2011.


Item 3. Defaults Upon Senior Securities

Not applicable.


Item 4. [Removed and Reserved]


Item 5. Other Information

Not applicable.

-25-

Rockies Region 2007 Limited Partnership
(A West Virginia Limited Partnership)




Item 6. Exhibits

The exhibits presented below are in addition to those presented in the Partnership's Form 10-K and subsequent quarterly filings on Form 10-Q.


 
 
 
 
Incorporated by Reference

Exhibit
Number
 
Exhibit Description
 
Form
 

SEC File
Number
 
Exhibit
 
Filing Date
 

Filed
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
31.1
 
Certification by Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) 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 Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) 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 Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
 
X

-26-

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
Petroleum Development Corporation (dba PDC Energy)

 
By: /s/ James M. Trimble
 
 
James M. Trimble
Chief Executive Officer
of Petroleum Development Corporation (dba PDC Energy)
 
 
August 8, 2011
 
 
 
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
August 8, 2011
James M. Trimble
 
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner of the Registrant
 
 
 
(Principal executive officer)
 
 
 
 
 
/s/ Gysle R. Shellum
 
Chief Financial Officer
August 8, 2011
Gysle R. Shellum
 
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner of the Registrant
 
 
 
(Principal financial officer)
 
 
 
 
 
/s/ R. Scott Meyers
 
Chief Accounting Officer
August 8, 2011
R. Scott Meyers
 
Petroleum Development Corporation (dba PDC Energy)
Managing General Partner of the Registrant
 
 
 
(Principal accounting officer)
 
 

-27-