UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


WASHINGTON, DC 20549





FORM 10-K





þ  ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934





For the fiscal year ended December 31, 2010


or


o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934





Commission File Number  000-53201





Rockies Region 2007 Limited Partnership


(Exact name of registrant as specified in its charter)





West Virginia
26-0208835(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)





1775 Sherman Street, Suite 3000, Denver, Colorado  80203


(Address of principal executive offices)     (Zip code)





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





Securities registered pursuant to Section 12(b) of the Act:  None





Securities registered pursuant to Section 12(g) of the Act:





Title of Each Class





Limited Partnership Interests





Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes   ̈  No þ





Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  ̈  No þ





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 and (2) has been subject to such filing requirements for the past 90 days.


Yes þ  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  ̈ No  ̈





Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ





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 definition 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        þ





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





State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter:





There is no trading market in the Partnership’s securities.  Therefore, there is no aggregate market value.





As of December 31, 2010, the Partnership had 4,470 units of limited partnership interest and no units of additional general partnership interest outstanding.












ROCKIES REGION 2007 LIMITED PARTNERSHIP


2010 ANNUAL REPORT ON FORM 10-K


TABLE OF CONTENTS




PagePART IItem 1
Business
3Item 1A
Risk Factors
21Item 1B
Unresolved Staff Comments
21Item 2
Properties
21Item 3
Legal Proceedings
21Item 4
[Removed and Reserved]
21PART IIItem 5
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
22Item 6
Selected Financial Data
24Item 7
Management’s Discussion and Analysis of Financial Condition and Results of Operations
24Item 7A
Quantitative and Qualitative Disclosures About Market Risk
37Item 8
Financial Statements and Supplementary Data
37Item 9
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
37Item 9A
Controls and Procedures
38Item 9B
Other Information
39PART IIIItem 10
Directors, Executive Officers and Corporate Governance
40Item 11
Executive Compensation
44Item 12
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
45Item 13
Certain Relationships and Related Transactions, and Director Independence
45Item 14
Principal Accountant Fees and Services
47PART IVItem 15
Exhibits, Financial Statement Schedules
48Signatures
50Financial Statements
F-1




Table of Contents





PART I








WHERE YOU CAN FIND MORE INFORMATION





The Rockies Region 2007 Limited Partnership (the “Partnership” or the “Registrant”) is subject to the reporting and information requirements of the Securities Exchange Act of 1934, as amended, and is as a result obligated to file periodic reports, proxy statements and other information with the SEC.  The SEC maintains a website that contains the annual, quarterly, and current reports, proxy and information statements, and other information regarding the Partnership, which the Partnership electronically files with the SEC.  The address of that site is http://www.sec.gov.  The Central Index Key, or CIK, for the Partnership is 0001407805.  You can read and copy any materials the Partnership files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1850, Washington, D.C.  20549.  You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.





UNITS OF MEASUREMENT





The following presents a list of units of measurement used throughout the document.





Bbl – One barrel of crude oil or NGL (Natural Gas Liquids) or 42 gallons of liquid volume.


Bcf – One billion cubic feet of natural gas volume.


Bcfe – One billion cubic feet of natural gas equivalent.


Btu – British thermal unit.


BBtu – One billion British thermal units.


MBbls – One thousand barrels of crude oil or NGLs.


Mcf – One thousand cubic feet of natural gas volume.


Mcfe – One thousand cubic feet of natural gas equivalent (six Mcf of natural gas equals one Bbl of crude oil or NGL).


MMBtu – One million British thermal units.


MMcf – One million cubic feet of natural gas volume.


MMcfe – One million cubic feet of natural gas equivalent.





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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS





This report 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 (the “Exchange Act”) regarding Rockies Region 2007 Limited Partnership’s 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.  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, which include statements of estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner’s strategies, plans and objectives.  However, these 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 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, worldwide demand, and commodity prices for natural gas, NGLs and crude oil;


·
changes in estimates of proved reserves;


·
declines in the values of the Partnership’s natural gas and crude oil properties resulting in impairments;


·
the timing and extent of the Partnership’s success in further developing and producing reserves;


·
the Managing General Partner’s ability to acquire drilling rig services, supplies and services at reasonable prices;


·
risks incident to the additional Codell formation development and operation of natural gas and crude oil wells;


·
future production and additional Codell formation development costs;


·
the availability of Partnership future cash flows for investor distributions or funding of additional Codell formation development activities;


·
the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on price;


·
the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America, or U.S.;


·
changes in environmental laws and the regulation and enforcement related to those laws;


·
the identification of and severity of environmental events and governmental responses to the events;


·
the effect of natural gas and crude oil derivatives activities;


·
the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all;


·
conditions in the capital markets; and


·
losses possible from pending or future litigation.





Further, the Partnership urges the reader to carefully review and consider the disclosures made in this report and the Partnership’s other filings with the SEC.  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.





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ITEM 1.
BUSINESS




General Information





The Partnership is a privately subscribed West Virginia Limited Partnership which owns an undivided working interest in natural gas and crude oil wells located in Colorado from which the Partnership produces and sells natural gas, NGLs and crude oil. The Partnership was organized and began operations in 2007 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”) and the Managing General Partner.  The Investor Partners own 63% of the Partnership’s capital, or equity interests.  PDC, the Managing General Partner, a Nevada Corporation, owns the remaining 37% of the Partnership’s capital, or equity interest. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner that governs the drilling and operational aspects of the Partnership.  In accordance with the Limited Partnership Agreement (the “Agreement”), general partnership interests were converted to limited partnership units at the completion of the Partnership’s drilling activities.  The Partnership expended substantially all of the capital raised in the offering for the initial drilling and completion of the Partnership’s wells.





The Managing General Partner may repurchase Investor Partner units, under certain circumstances provided by the Agreement, upon request of an individual investor partner.  For more information about the Managing General Partner’s limited partner unit repurchase program as well as the current number of Investor Partners as of the date of filing, see Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.  For information concerning the Managing General Partner’s ownership interests in the Partnership as of the date of filing, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.





The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership’s wells are depleted or becomes uneconomical to produce, at which time that well 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.





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





Recent Developments





PDC Sponsored Drilling Program Acquisition Plan





PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, beginning in the fall of 2010 and extending through the next three years, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of that partnership other than PDC or its affiliates (“non-affiliated Investor Partners”), in the limited partnerships that PDC has sponsored, including this Partnership.  For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships, refer to the disclosure included in Items 2.02, 7.01 and/or 8.01 of PDC’s Forms 8-K dated March 4, 2010, June 9, 2010, July 15, 2010 and November 17, 2010.  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 and the approval by a majority of the limited partnerships units held by the non-affiliated Investor Partners of each respective limited partnership.  Consummation of any proposed merger of a PDC sponsored limited partnership under the Acquisition Plan will likely result in the termination of the existence of that partnership and the right of non-affiliated Investor Partners to receive a cash payment for their limited partnership units in that partnership.




In December 2010, PDC acquired four affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership. PDC purchased these partnerships for the aggregate amount of $34.8 million.





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In November 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership, and the 2005 Rockies Region Private Limited Partnership (collectively, the “2005 partnerships”).  PDC serves as the managing general partner of each of the 2005 partnerships.  Definitive proxy statements for each of the 2005 partnerships requesting approval for the applicable merger were mailed to the non-affiliated Investor Partners of the 2005 partnerships on February 7, 2011.  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 such partnership will merge with and into a wholly-owned subsidiary of PDC.  There is no assurance the partnerships will obtain the necessary approvals from non-affiliated investors.  PDC has re-evaluated the merger consideration agreed to in the merger agreements and has proposed to offer supplemental merger consideration to the non-affiliated Investor Partners of the 2005 partnerships in addition to the merger consideration described above.  On March 25, 2011, the special meeting of non-affiliated Investor Partners of the 2005 partnerships was adjourned until May 27, 2011.  PDC expects to send non-affiliated Investor Partners of the 2005 partnerships a proxy supplement that provides information relating to the increased merger consideration and also includes such Partnership’s year-end financial statements and the Partnership’s 2010 year-end reserve report.  Although there is no assurance of the likelihood or timing of the completion of the SEC proxy disclosure review process or whether each Partnership will obtain the necessary approvals from non-affiliated Investors Partners, PDC would expect to mail such proxy supplements to the non-affiliated Investors Partners of the 2005 partnerships in late April or early May.


The feasibility and timing of any future 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 additional Codell formation development; 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 2005 partnerships, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur.





Business Strategy





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





The Partnership’s business plan going forward, including the Additional Codell Formation Development Plan, is to produce and sell the natural gas, NGLs and crude oil from the Partnership’s wells, and to make distributions to the partners as outlined in the Partnership’s cash distribution policy discussed in Item 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.  Partnership cash distributions may be withheld pursuant to the Additional Codell Formation Development Plan.





Operations





General.  When Partnership wells were "completed" (i.e., drilled, fractured or stimulated, and all surface production equipment and pipeline facilities necessary to produce the well were installed) production operations commenced on each well.  All Partnership wells are completed, and production operations are currently being conducted with regard to each of the Partnership’s productive wells.





PDC, in accordance with the D&O Agreement, is the named operator of record of the Partnership’s wells and may, in certain circumstances, provide equipment and supplies, perform salt water disposal and other services for the Partnership.  Generally, equipment and services are sold to the Partnership at the lower of cost or competitive prices in the area of operations.  The Partnership's share of production revenue from a given well is burdened by and subject to, royalties and overriding royalties, monthly operating charges, production taxes and other operating costs.  It is PDC's practice to deduct operating expenses from the production revenue for the corresponding period.  In instances when distributable cash flows are insufficient to make full payment, PDC defers the collection of operating expenses until such time as scheduled expenses may be offset against future Partnership distributable cash flows.  In such instances, the Partnership records a liability to PDC.





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The Partnership’s operations are concentrated in the Rocky Mountain Region where weather conditions and time periods reserved by leasehold restrictions can exist and limit operational capabilities for as long as six months.  Operational constraint challenges such as surface equipment freezing can limit production volumes.  Increased competition for oil field equipment, services, supplies and qualified personnel and wildlife habitat protection periods may also adversely affect profitability and reduce cash distributions to the Investor Partners.





Areas of Operations





The Partnership’s operating areas are profiled as follows:





Wattenberg Field, DJ Basin, Weld County, Colorado.  Located north and east of Denver, Colorado, the Partnership’s wells in this field exhibit production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels.  Although natural gas is the primary hydrocarbon produced, many wells also produce NGLs and/or crude oil.  Of the Partnership’s 75 wells drilled in the Wattenberg Field, 69 were initially completed and currently produce from the Codell formation.  Of these Codell formation wells, 67 were also completed in the shallower Niobrara formation.  In addition to the shallower formation well completions, the Partnership also completed wells, including one Dakota formation well and five J-Sand formation wells, that currently produce from deeper formations.  The Partnership’s development wells in this area are generally 7,000 to 8,000 feet in depth.  Well spacing ranges from 20 to 40 acres per well.





Grand Valley Field, Piceance Basin, Garfield County, Colorado. Located near the western border of Colorado, the Partnership’s 24 wells in this field have also exhibited production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels.  These wells generally produce natural gas along with small quantities of crude oil.  In addition to the Grand Valley Field’s producing wells, one additional well (1.0 net) drilled in the field was declared to be a developmental dry hole due to downhole mechanical failure and was subsequently plugged and abandoned.  The majority of the Partnership’s development wells drilled in the area were drilled directionally from multi-well pads ranging from two to eight or more wells per drilling pad.  The primary drilling targets were multiple sandstone reservoirs in the Mesa Verde formation and well depth ranges from 7,000 to 9,500 feet. Well spacing is approximately 10 acres per well.





Title to Properties





The Partnership's leases are direct interests in producing acreage.  In accordance with the D&O Agreement, the Managing General Partner exercised due care and judgment, which included curative work for any title defect when discovered, to ensure that each Partnership’s well bore working interest assignment, made effective on the date of well spudding, was properly recorded in county land records.  The Partnership believes it holds good and defensible title to its developed properties, in accordance with standards generally accepted in the industry, through the record title held in the Partnership’s name, of each Partnership well’s working interest.  The Partnership’s properties are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The Managing General Partner is not aware of any additional burdens, liens or encumbrances customary to the industry, if any, which may materially interfere with the commercial use of the properties.  Provisions of the Agreement generally relieve PDC from errors in judgment with respect to the waiver of title defects.





Drilling and Other Development Activities





Natural Gas and Crude Oil Properties.  The Partnership’s properties (the “Properties”) consist of a working interest in the well bore in each well drilled by the Partnership.  The Partnership drilled 100 wells (98.9 net) (the number of gross wells multiplied by the working interest in the wells owned by the Partnership) during drilling operations that began immediately after funding and concluded in September 2008 when the last of the Partnership’s  99 productive wells were connected to sales and gathering lines.  One Grand Valley Field well (1.0 net) was declared to be a developmental dry hole due to downhole mechanical failure and was subsequently plugged and abandoned. No exploratory drilling activity was conducted on behalf of the Partnership.  The 100 wells discussed above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been expended.





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The following table presents the Partnership’s productive wells by operating field as of December 31, 2010 and 2009.  Productive wells consist of producing wells and wells capable of producing natural gas and/or NGLs and crude oil in commercial quantities.





Producing Gas Wells2010


2009Location

Gross


Net


Gross


NetState of ColoradoPiceance Basin: Grand Valley Field


24.0



24.0



24.0



24.0Denver-Julesburg (DJ) Basin: Wattenberg Field


75.0



73.9



75.0



73.9Total Colorado


99.0



97.9



99.0



97.9Total Productive Wells


99.0



97.9



99.0



97.9





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 and 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 Wattenberg Field 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 distributable cash flows.





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 development activities are funded in part through borrowing, potential distributable cash flows 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 withholding funds from several of the PDC sponsored partnerships, on a pro-rata basis, allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, from distributable cash flows of the Partnership resulting from current production.  The funds retained are necessary for the Partnership to pay for refracturing or recompletion costs and will materially reduce, up to 100%, distributable cash flows of the Partnership for a period of time not to exceed five years.  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.





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Current estimated costs for these well refracturings and recompletions are between $175,000 and $240,000 per activity.  As of December 31, 2010, this Partnership has scheduled to complete 77 additional Codell formation development opportunities.  This increase from 75 potential additional Codell formation development opportunities as of December 31, 2009 is due to an increase in estimated future distributable cash flows based on current pricing and well economics.  Total withholding for these activities from the Partnership’s distributable cash flows 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.  As of December 31, 2010, $120,000 has been withheld from the Partnership distributions for these refracturings or recompletions.  Cumulatively, $370,000 has been withheld from Partnership distributions through February 28, 2011.





Implementation of the Additional Codell Formation Development Plan would 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.





Proved Reserves





All of the Partnership’s proved reserves are located in the United States.  The Partnership’s reserve estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a), and subsequent SEC staff regulations, interpretations and guidance.  All of the Partnership’s proved reserves have been estimated by independent engineers.





The Managing General Partner established a comprehensive process that governs the determination and reporting of the Partnership’s proved reserves.  As part of the Managing General Partner’s internal control process, the Partnership’s reserves are reviewed annually by a team composed of PDC reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data as well as production performance data.  The review includes, but is not limited to, confirmation that reserve estimates (1) include all properties owned; (2) are based on proper working and net revenue interests; and (3) reflect reasonable cost estimates and field performance.  The internal team compiles the reviewed data and forwards the data to an independent consulting firm engaged to estimate the Partnership’s reserves.





The Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. (Ryder Scott), to estimate the Partnership’s 2010 and 2009 reserves.  When preparing the Partnership's reserve estimates, the independent engineer did not independently verify the accuracy and completeness of information and data furnished by the Managing General Partner with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices, or any agreements relating to current and future operations of properties and sales of production.





The independent petroleum engineer prepared an estimate of the Partnership’s reserves in conjunction with an ongoing review by the Managing General Partner’s engineers.  A final comparison of data was performed to ensure that the reserve estimates were complete, determined by acceptable industry methods and to a level of detail the Managing General Partner deems appropriate.  The final independent petroleum engineer's estimated reserve report was reviewed and approved by the Managing General Partner’s engineering staff and management.





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The professional qualifications of the Managing General Partner’s lead engineer primarily responsible for overseeing the preparation of the Partnership’s reserve estimate meets the standards of Reserves Estimator as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers.  This Managing General Partner employee holds a Bachelor of Science degree in Petroleum and Natural Gas Engineering and has over 25 years of experience in reservoir engineering.  The individual is a member of the Society of Petroleum Engineers, allowing the individual to remain current with the developments and trends in the industry.  Further, during 2009, this individual attended ten hours of formalized training relating to the definitions and disclosure guidelines set forth in the SEC's final rule released January 2009, Modernization of Oil and Gas Reporting.





Proved reserves are those quantities of natural gas, NGLs and crude oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  These reserve quantities are projected to be producible prior to the operating contract’s expiration date, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. The Partnership’s net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate.  The Partnership’s two categories of proved reserves are as follows:





·
Proved developed reserves are those natural gas, NGLs and crude oil quantities expected to be recovered from currently producing zones under the continuation of present operating methods.


·
Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for refracturing or recompletion.





The table below presents information regarding the Partnership’s estimated proved reserves.  Prior to 2010, the Partnership’s NGLs reserves were included in and reported with natural gas reserves, which impacts the comparability of 2010 reserve information to previously reported 2009 reserve information.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Reporting on NGLs in 2010 for additional information.





Reserves cannot be measured exactly, because reserve estimates involve judgments.  The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance data, new geological and geophysical data and economic changes.  The Partnership’s estimated proved undeveloped reserves consist entirely of reserves attributable to the Wattenberg Field’s future initial Codell formation recompletion of the five productive J-Sand wells and future refracturings of 72 of the Codell formation wells.  (See Item 1, Business−Operations, Drilling and Other Activities-Additional Codell Formation Development Plan on page 6.)  For additional information regarding the Partnership’s reserves see the  Net Proved Reserves section of the Supplemental Information provided with the financial statements included in this report.  There were no proved undeveloped reserves that were developed in 2010.





December 31,

2010Proved ReservesNatural gas (MMcf)


20,291Crude Oil and Condensate (MBbl)


1,125NGLs (MBbl)


465Total proved reserves (MMcfe)


29,831




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An economically producible quantity is one where the revenue provided by its sale is reasonably likely to exceed the cost to deliver that quantity to market.  Prices used to estimate future gross revenues and production and development costs considered in the estimation of economically producible natural gas, NGLs and crude oil reserve quantities presented above, were based on the following:





Gross revenues


·
A 12-month average price calculated as the unweighted arithmetic average of the price on the first day of each month, January through December.


·
Prices were adjusted by lease for Btucontent, transportation and regional price differences; however, they were not adjusted to reflect the value of the Partnership’s commodity hedges.


Production and development costs


·
Costs as of December 31 for each of the respective years presented.


·
The amounts shown do not give effect to non-property related expenses, such as direct costs−general and administrative expenses or to depreciation, depletion and amortization expense.





The following table presents the Partnership’s estimated proved reserves by type and by field:





As of December 31, 2010Natural Gas

(MMcf)


NGLs

(MBbl)


Crude Oil and

Condensate

(MBbl)


Natural Gas

Equivalent

(MMcfe)


PercentProved developedPiceance Basin: Grand Valley Field


14,801



-



38



15,029



72
%Denver-Julesburg (DJ) Basin: Wattenberg Field


2,182



185



437



5,914



28
%Total proved developed


16,983



185



475



20,943



100
%Proved undevelopedPiceance Basin: Grand Valley Field


-



-



-



-



0
%Denver-Julesburg (DJ) Basin: Wattenberg Field


3,308



280



650



8,888



100
%Total proved undeveloped


3,308



280



650



8,888



100
%Proved reservesPiceance Basin: Grand Valley Field


14,801



-



38



15,029



50
%Denver-Julesburg (DJ) Basin: Wattenberg Field


5,490



465



1,087



14,802



50
%Total proved reserves


20,291



465



1,125



29,831



100
%




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Production, Sales, Prices and Lifting Costs - By Field





The following table presents information regarding the Partnership’s production volumes, natural gas, NGLs and crude oil sales, average sales price received and average production cost by field.  Prior to 2010, NGLs were included in natural gas.  As a result for the Denver-Julesberg (DJ) Basin: Wattenberg Field information, natural gas production, sales and average sales price comparability are impacted for 2010 to 2009.  However, total production at the Mcfe level, sales by field and average price per Mcfe are comparable.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Reporting on NGLs in 2010 for additional details.





Year Ended December 31,2010


2009Production(1)Natural gas(Mcf)Piceance Basin: Grand Valley Field


1,886,023



3,172,933Denver-Julesberg (DJ) Basin: Wattenberg Field


357,863



728,490Total Natural Gas


2,243,886



3,901,423Crude Oil (Bbl)Piceance Basin: Grand Valley Field


5,763



9,568Denver-Julesberg (DJ) Basin: Wattenberg Field


74,767



134,153Total Crude Oil


80,530



143,721NGLs (Bbl)Denver-Julesberg (DJ) Basin: Wattenberg Field


29,497



-Natural gas equivalent (Mcfe)Piceance Basin: Grand Valley Field


1,920,601



3,230,341Denver-Julesberg (DJ) Basin: Wattenberg Field


983,447



1,533,408Total natural gas equivalent


2,904,048



4,763,749Natural Gas, NGLs and Crude Oil SalesNatural gas salesPiceance Basin: Grand Valley Field

$
6,447,652


$
7,960,226Denver-Julesberg (DJ) Basin: Wattenberg Field


1,394,974



2,418,236Total natural gas sales


7,842,626



10,378,462Crude oil salesPiceance Basin: Grand Valley Field

$
357,903


$
388,521Denver-Julesberg (DJ) Basin: Wattenberg Field


5,503,224



7,493,953Total crude oil sales


5,861,127



7,882,474NGLs salesDenver-Julesberg (DJ) Basin: Wattenberg Field

$
785,262


$
-Natural gas, NGLs and crude oil salesPiceance Basin: Grand Valley Field

$
6,805,555


$
8,348,747Denver-Julesberg (DJ) Basin: Wattenberg Field


7,683,460



9,912,189Total natural gas, NGLs and crude oil sales

$
14,489,015


$
18,260,936Average Sales Price (excluding realized gain on derivatives)Natural gas(per Mcf)Piceance Basin: Grand Valley Field

$
3.42


$
2.51Denver-Julesberg (DJ) Basin: Wattenberg Field


3.90



3.32Average sales price natural gas, all fields


3.50



2.66Crude Oil (per Bbl)Piceance Basin: Grand Valley Field

$
62.10


$
40.61Denver-Julesberg (DJ) Basin: Wattenberg Field


73.60



55.86Average sales price crude oil, all fields


72.78



54.85NGLs (per Bbl)Denver-Julesberg (DJ) Basin: Wattenberg Field

$
26.62


$
-Natural gas equivalent (per Mcfe)Piceance Basin: Grand Valley Field

$
3.54


$
2.58Denver-Julesberg (DJ) Basin: Wattenberg Field


7.81



6.46Average sales price natural gas equivalents, all fields


4.99



3.83Average Production (Lifting) Cost(2) (per Mcfe)Piceance Basin: Grand Valley Field

$
1.73


$
0.83Denver-Julesberg (DJ) Basin: Wattenberg Field


1.16



0.73Average production cost, all fields


1.54



0.80




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


(2)
Average production unit costs presented exclude the effects of ad valorem and severance taxes.





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For more information concerning the Partnership’s production volumes and costs, which include severance and ad valorem taxes as reflected in the Partnership’s statements of operations accompanying this report, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report.





Natural Gas, NGLs and Crude Oil Sales





In accordance with the D&O Agreement, PDC markets the natural gas, NGLs and crude oil produced from the Partnership’s wells primarily to other gas marketers, utilities, industrial end-users and other wholesale gas purchasers.  The Managing General Partner generally sells the natural gas that the Partnership produces under contracts with indexed monthly pricing provisions.  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. This monthly charge is more fully described in the following Item 1, Business−Reliance on the Managing General Partner, Provisions of the D&O Agreement.  Virtually all of the Partnership’s contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies.  As a result, the Partnership’s revenues from the sale of natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline.  The Managing General Partner believes that the pricing provisions of the Partnership’s natural gas contracts are customary in the industry.  The Managing General Partner also enters into financial derivatives in order to reduce the impact of possible price instability regarding the physical sales market.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation: Results of Operations – Commodity Price Risk Management, Netand Note 4, Derivative Financial Instruments, to the Partnership’s financial statements included in this report.





In general, the Managing General Partner has been and expects to continue to be able to produce and sell natural gas and NGLs from the Partnership’s wells without significant curtailment and at competitive prices.  The Partnership does, however, experience limited curtailments from time to time due to pipeline maintenance and operating issues.  Open access transportation through the country's interstate pipeline system gives us access to a broad range of markets.  Whenever feasible, the Managing General Partner obtains access to multiple pipelines and markets from each of the Partnership’s gathering systems, seeking the best available market for the Partnership’s natural gas at any point in time.





The wells in the Partnership’s Wattenberg Field and, to a significantly lesser extent, the Grand Valley Field wells, produce crude oil as well as natural gas and NGLs.  The Managing General Partner is currently able to sell all the crude oil that the Partnership can produce under existing sales contracts with petroleum refiners and marketers.  The Partnership does not refine any of the Partnership’s crude oil production.  The Partnership’s crude oil production is sold to purchasers at or near the Partnership’s wells under both short and long-term purchase contracts with monthly pricing provisions.





Transportation and Gathering





The Partnership’s natural gas and NGLs are transported through the Managing General Partner’s and third party gathering systems and pipelines, and the Partnership incurs processing, gathering and transportation expenses to move the Partnership’s natural gas and related NGLs from the wellhead to a purchaser-specified delivery point.  These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter.  Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas transporters.  While the Managing General Partner’s ability to market the Partnership’s natural gas and NGLs have been only infrequently limited or delayed, if transportation space is restricted or is unavailable, the Partnership’s cash flow from the affected properties could be adversely affected.  In order to meet pipeline specifications, the Managing General Partner is required, in some cases, to process the Partnership’s natural gas before it can be transported.  The Managing General Partner typically contracts with third parties in the Grand Valley area of the Rocky Mountain Region for firm transportation of the Partnership’s natural gas and NGLs.





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Delivery Commitments





On behalf of the Partnership, other sponsored drilling program partnerships and for its own corporate account, PDC has entered into third-party sales and processing agreements that generally contain indexed monthly pricing provisions.  Although the Partnership is not committed to deliver any fixed and determinable quantities of natural gas or oil under the terms of these agreements, the dedication of the Partnership’s future production is as follows:





·
Wattenberg Field contractual natural gas and NGLs processing and sales dedications are multi-year and extend throughout the well’s economic life.


·
Grand Valley Field contractual natural gas processing and firm sales dedications extend through 2022 and the contract provides the seller with the right to convert to a gathering and gas processing contract, solely.


·
Oil sales dedication is made under a 2-year master agreement with negotiated extensions.





Delivery to Market





The Partnership relies on PDC owned or third-party gathering and transmission pipelines to transport natural gas and NGLs production volumes to customers.  In general, the Partnership has been, and expects to continue to be able to, produce and sell natural gas and NGLs from Partnership wells without significant curtailment.  The Partnership does experience limited curtailments from time to time due to pipeline maintenance and operating issues of the pipeline operators.





Seasonal curtailment typically occurs during July and August as a result of high atmospheric temperatures which reduce compressor efficiency.  This reduction in production typically amounts to less than five percent of normal monthly production.  The cost, timing and availability of gathering pipeline connections and service varies from area to area, well to well, and over time.  Although the Rockies Region has experienced a natural gas transport capacity shortage in the past several years, several key projects placed in-service during the past two years, including the completion of the 1,679-mile Rockies Express Pipeline which extends from Colorado to eastern Ohio and White River Header Pipeline Project in Colorado, have significantly increased natural gas deliverability to intra-regional urban areas as well as inter-regionally, especially to markets in the North Central and Northeastern U.S. as well as Southern California.Transmission capacity is expected to increase in the future based on projects scheduled before various regulatory agencies, but may be delayed due to the recent economic downturn which has weakened U.S. natural gas, NGLs and crude oil demand and disrupted global credit markets, which third-party entities access for  pipeline expansion financing.





The Partnership oil production is stored in tanks at or near the location of the Partnership’s wells for routine pickup by oil transport trucks for direct delivery to regional refineries or oil pipeline interconnects for redelivery to those refineries.  The cost of trucking or transporting the oil to market affects the price the Partnership ultimately receives for the oil.





Commodity Price Risk Management Activities





The Managing General Partner, on behalf of the Partnership in accordance with the D&O Agreement, utilizes commodity based derivative instruments to manage a portion of the Partnership’s exposure to price volatility with regard to the Partnership’s natural gas and crude oil sales.  The financial instruments generally consist of collars, swaps and basis swaps and are NYMEX-traded and Colorado Interstate Gas, or CIG, based contracts.  The Managing General Partner may utilize derivatives based on other indices or markets where appropriate.  The contracts economically provide price stability for committed and anticipated natural gas and crude oil sales, generally forecasted to occur within the next two to four-year period.  The Partnership’s policies prohibit the use of commodity derivatives for speculative purposes and permit utilization of derivatives only if there is an underlying physical position.  The Managing General Partner manages price risk on only a portion of the Partnership’s anticipated production, so the remaining portion of the Partnership’s production is subject to the full fluctuation of market pricing.





The Managing General Partner uses financial derivatives to establish "floors" and "ceilings" or "collars" on the possible range of the prices realized for the sale of natural gas and crude oil in addition to fixing prices by using swaps.  These derivatives are carried on the balance sheets at fair value with changes in fair values recognized currently in the statement of operations.





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The Partnership is subject to price fluctuations for natural gas and crude oil sold in the spot market and under market index contracts.  The Managing General Partner continues to evaluate the potential for reducing these risks by entering into derivative transactions.  In addition, the Managing General Partner may close out any portion of derivatives that may exist from time to time which may result in a realized gain or loss on that derivative transaction.





Governmental Regulation





While the prices of natural gas, NGLs and crude oil are market driven, other aspects of the Partnership’s business and the industry in general are heavily regulated.  The availability of a ready market for natural gas, NGLs and crude oil production depends on several factors beyond the Partnership’s control.  These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas, NGLs and crude oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels.  State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of natural gas, NGLs and crude oil, to prevent waste of natural gas, NGLs and crude oil, to protect rights among owners in a common reservoir and to control contamination of the environment.  Pipelines are subject to the jurisdiction of various federal, state and local agencies.  In the western part of the U.S., the federal and state governments own a large percentage of the land and the rights to develop natural gas and crude oil.  Generally, government leases are subject to additional regulations and controls not commonly seen on private leases.  The Managing General Partner takes the steps necessary to comply with applicable regulations, both on its own behalf and as part of the services provided to sponsored drilling partnerships.  The Managing General Partner believes that it is in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case.  The following summary discussion of the regulation of the U.S. oil and natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Partnership’s operations may be subject.





Regulation of Natural Gas, NGLsand Crude Oil Production.  The Partnership’s production business is subject to various federal, state and local laws and regulations on the taxation of natural gas, NGLs and crude oil, the development, production and marketing of natural gas, NGLs and crude oil and environmental and safety matters.  Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters.  Prior to commencing drilling activities for a well, the Managing General Partner must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located.  The permits and approvals include those for the drilling of wells.  Additionally, other regulated matters include:





·
bond requirements in order to drill or operate wells;


·
the location of wells;


·
the method of drilling and casing wells;


·
the surface use and restoration of well properties;


·
the plugging and abandoning of wells; and


·
the disposal of fluids.





The Partnership’s operations are also subject to various conservation laws and regulations.  These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of properties.  In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases.  In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold.  In addition, state conservation laws may establish maximum rates of production from natural gas and crude oil wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production.  Where wells are to be drilled on state or federal leases, additional regulations and conditions may apply.  The effect of these regulations may limit the amount of natural gas, NGLs and crude oil that can be produced from the Partnership’s wells and may limit the number of wells or the locations which can be drilled.  Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning the Partnership’s natural gas and crude oil wells and other facilities.  In addition, these laws and regulations, and any others that are passed by the jurisdictions where the Partnership has production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit the Partnership’s reserves.  As a result, the Managing General Partner is unable to predict the future cost or effect of complying with such regulations.





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Regulation of Sales and Transportation of Natural Gas.  Historically, the price of natural gas was subject to limitation by federal legislation.  The Natural Gas Wellhead Decontrol Act removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales" on or after that date.  The Federal Energy Regulatory Commission's, or FERC, jurisdiction over natural gas transportation was unaffected by the Decontrol Act.





The Managing General Partner moves natural gas and NGLs through pipelines owned by other companies, and sells natural gas and NGLs to other companies that also utilize common carrier pipeline facilities.  Natural gas pipeline interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation.  Each natural gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA.  Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities.  FERC regulations govern how interstate pipelines communicate and do business with their affiliates.  Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates.





Each interstate natural gas pipeline company establishes its rates primarily through the FERC’s rate-making process.  Key determinants in the ratemaking process are:





·
costs of providing service, including depreciation expense;


·
allowed rate of return, including the equity component of the capital structure and related income taxes; and


·
volume throughput assumptions.





The availability, terms and cost of transportation affect the Partnership’s natural gas and NGLs sales.  In the past, FERC has undertaken various initiatives to increase competition within the industry.  As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system was substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers.  The most significant provisions of Order No. 636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers.  In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services.  Another effect of regulatory restructuring is greater access to transportation on interstate pipelines.  In some cases, producers and marketers have benefited from this availability.  However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare.  Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates.  Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently the Managing General Partner has seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in-gas, which could adversely affect cash flows from the affected area.





Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts.  The industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue.  The Managing General Partner cannot determine to what extent the Partnership’s future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels.





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Environmental Matters





The Partnership’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.  Public interest in the protection of the environment has increased dramatically in recent years.  The trend of more expansive and tougher environmental legislation and regulations is expected to continue.  To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs and reduced access to the industry in general, the Partnership’s business and prospects could be adversely affected.





The Partnership generates waste that may be subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes.  The U.S. Environmental Protection Agency, or EPA, and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes.  Furthermore, certain wastes generated by the Partnership’s operations that are currently exempt from treatment as "hazardous wastes" may, in the future, be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements.





The Partnership currently owns properties that for many years have been used for the exploration and production of natural gas, NGLs and crude oil.  Although the Partnership believes that the Partnership has utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques, and hydrocarbons or other wastes may have been disposed of or released on or under the properties that the Partnership owns or on or under locations where such wastes have been taken for disposal.  These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, RCRA and analogous state laws, as well as state laws governing the management of natural gas and crude oil wastes.  Under such laws, the Managing General Partner could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.





CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment.  These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site.  Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  As an owner and operator of natural gas and crude oil wells, the Partnership may be liable pursuant to CERCLA and similar state laws.





The Partnership’s operations may be subject to the Clean Air Act, or CAA, and comparable state and local requirements.  Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the Partnership’s operations.  The EPA and states have been developing regulations to implement these requirements.  The Partnership has been required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues.  The State of Colorado has also implemented new air emission regulations in 2009, which affect the industry, including the Partnership’s operations.





The Federal Clean Water Act, or CWA, and analogous state laws impose strict controls against the discharge of pollutants, including spills and leaks of crude oil and other substances.  The CWA also regulates storm water run-off from natural gas and crude oil facilities and requires a storm water discharge permit for certain activities.  Spill prevention, control, and countermeasure requirements of the CWA require appropriate containment terms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak.





Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills.  Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including the Partnership, to procure and implement Spill Prevention, Control and Counter-measures plans relating to the possible discharge of crude oil into surface waters.  The Oil Pollution Act of 1990, or OPA, subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills.  Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.  The Partnership is also subject to the CWA and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release of petroleum or its derivatives into surface waters or into the ground.  Historically, the Partnership has not experienced any significant crude oil discharge or crude oil spill problems.





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In 2009, the State of Colorado’s Oil and Gas Conservation Commission implemented new broad-based environmental and wildlife protection regulations for the industry.  These regulations will continue to increase the Partnership’s costs.  The Partnership’s expenses relating to preserving the environment have risen over the past few years and are expected to continue to rise in 2011 and beyond.  Environmental regulations have had no materially adverse effect on the Partnership’s ability to operate to date, but no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on the Partnership’s business, financial condition or results of operations.





Industry Regulation





While the prices of natural gas, NGLs and crude oil are set by the market, other aspects of the Partnership's business and the industry in general are heavily regulated.  The following summary discussion of the regulation of the United States industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Partnership's operations may be subject.





Legislative proposals and proceedings that might affect the petroleum and natural gas industries occur frequently in Congress, FERC, state commissions, state legislatures, and the courts.  These proposals involve, among other things, imposition of direct or indirect price limitations on natural gas production, expansion of drilling opportunities in areas that would compete with Partnership production, imposition of land use controls, landowners' "rights" legislation, alternative fuel use requirements and tax incentives and other measures.  The petroleum and natural gas industries historically have been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue.  The Partnership cannot determine to what extent its future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels.  Illustrative of this trend are the regulations implemented in 2009 by the State of Colorado, which focus on the natural gas and crude oil industry.  These multi-faceted regulations significantly enhance requirements regarding natural gas and crude oil permitting, environmental requirements and wildlife protection.  Permitting delays and increased costs could result from these final regulations. Other potential or recently enacted laws and regulations affecting the Partnership include the following:





·
The U.S. Environmental Protection Agency, or EPA, has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities.  The EPA has held public meetings around the country on this issue that have been well publicized and well attended.  This renewed focus could lead to additional federal and state laws and regulations affecting the Partnership’s additional Codell formation development, fracturing and operations.  Additional laws, regulations or other changes could significantly reduce the Partnership’s future additional Codell formation development opportunities, increase the Partnership’s costs of operations, and reduce the Partnership’s distributable cash flows, in addition to undermining the demand for the natural gas and crude oil the Partnership produces.


·
Several bills in Congress, if passed, would establish a "cap and trade" system regarding greenhouse gas emissions.  Companies would be assigned emission "allowances" under these bills which would decline each year.  In addition, new EPA greenhouse gas monitoring and reporting regulations may affect the Partnership and the third parties that process the Partnership’s natural gas, NGLs and crude oil.


·
New or increased severance taxes have been proposed in several states, which could adversely affect the existing operations in these states and the economic viability of future additional Codell formation development.




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·
In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”).  The Dodd-Frank Act regulates derivative transactions, including the Partnership’s natural gas and crude oil hedging swaps.  These swaps are broadly defined to include most of the Partnership’s hedging instruments.  The new law requires the issuance of new regulations and administrative procedures related to derivatives within one year.  The effect of such future regulations on the Partnership’s business is currently uncertain.  In particular, note the following:


i.
The Dodd-Frank Act may decrease the Managing General Partner’s ability to enter into hedging transactions which would expose the Partnership to additional risks related to commodity price volatility.  Commodity price decreases could then have an immediate significant adverse affect on the Partnership’s revenues and impair the Partnership’s ability to have certainty with respect to a portion of the Partnership’s distributable cash flows.  A reduction in cash flows may lead to decreased Investor Partner cash distributions or fewer completed Codell formation development activities and therefore, decreased Partnership’s proved reserves and future production.


ii.
The Managing General Partner expects that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased counterparty costs.  The Partnership’s derivative counterparties may be subject to significant new capital, margin and business conduct requirements imposed as a result of the new legislation.


iii.
The Dodd-Frank Act contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility.  There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk.  While the Partnership may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking proceedings.


iv.
The above factors could also affect the pricing of derivatives and make it more difficult for the Managing General Partner to enter into hedging transactions on behalf of the Partnership, on favorable terms.





Competitive Market Position





Competition is high among persons and companies involved in the exploration and production of natural gas and crude oil.  Because there are thousands of natural gas and crude oil companies in the United States, the national supply of natural gas, including the Rockies Region which currently supplies approximately 22% of the U.S. natural gas production annually, is diversified.  The Partnership believes that the drilling and production capabilities and the experience of the Managing General Partner’s management and professional staff generally enables the Partnership to compete effectively.  As a result of the well-publicized turmoil in the financial and commodity markets in late 2008, resultant industry slowdown throughout 2009 and the Managing General Partner’s cost reduction initiatives, the Partnership experienced overall reductions in its 2009 natural gas, NGLs and crude oil production costs.  During 2010, the Managing General Partner has seen service costs steadily rise as oil prices and low cost shale opportunities have led to rig and completion crew redeployment.  For more information on natural gas and crude oil pricing during 2010 and 2009, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Natural Gas and Crude Oil Sales.The Partnership believes that it can compete effectively in its area of operations.  Nevertheless, the Partnership’s results of operations and distributable cash flows could be materially adversely affected by the uncertainty in ascertaining the ultimate depth and duration of the current economic environment.





As a result of Federal Energy Regulatory Commission, or FERC, and Congressional deregulation of natural gas and crude oil prices in the past, prices are generally determined by competitive supply-and-demand market forces.  The marketing of natural gas, NGLs and crude oil produced by the Partnership is affected by a number of factors, some of which are beyond the Partnership's control and the exact effect of which cannot be accurately predicted.  These factors include the volume and prices of crude oil imports, the availability and cost of adequate natural gas and crude oil pipeline and other transportation facilities, the marketing of competitive fuels, such as coal, nuclear and renewable fuel energy and other matters affecting the availability of a ready market, such as fluctuating supply and demand.  Among other factors, the supply and demand balance of natural gas and crude oil in world markets combined with supply and demand balance within and across U.S. geographical regions may have caused significant variations in the prices of these traditional hydrocarbon products over recent years.





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The Partnership’s fields are crossed by natural gas pipelines belonging to DCP Midstream LP (“DCP”), Williams Production, RMT (“Williams”) and others.  These companies have all traditionally purchased substantial portions of their natural gas supply from Colorado producers.  The gas is sold at negotiated prices based upon a number of factors, including the quality of the gas, well pressure, estimated remaining reserves, prevailing supply conditions and any applicable price regulations promulgated by the FERC.  FERC natural gas pipeline open-access initiatives implemented during the mid-1980’s to mid-1990’s, mandated that interstate gas pipeline companies separate their merchant activities from their transportation activities and thus release, on both a short and a long-term basis, available transmission system capacity. Thus, local distribution companies have taken an increasingly active role in acquiring their own natural gas supplies.  Consequently, the Managing General Partner believes interstate transmission pipelines and local distribution companies (utilities) are buying natural gas directly from natural gas producers and marketers, and retail unbundling efforts are causing many end-users to buy their own reserves.  In general, the Partnership has been and expects to continue to be able to produce and sell natural gas, NGLs and crude oil from the Partnership’s wells at locally competitive prices.





The Partnership’s secondary hydrocarbon product is oil.  In contrast to U.S. natural gas pricing, which is determined more directly by North American supply-demand factors, crude oil pricing is subject to global supply-demand influences including the presence of the Organization of Petroleum Exporting Countries, or OPEC, whose members establish prices and production quotas for petroleum products of OPEC members from time to time.  The Managing General Partner is unable to predict what effect, if any, future OPEC actions will have on the quantity of, or prices received for, crude oil produced and sold from the Partnership's wells.





Colorado accounts for approximately 1% of the U.S.’s total annual domestic oil production and this production generally provides feedstock for Colorado’s two refineries located north of Denver and owned by Suncor Energy (USA) Inc. (“Suncor”).  Rocky Mountain oil sales have traded at a discount compared to supplies available elsewhere in the U.S. due to an excess supply situation in the region that arose as a result of rising Canadian tar sand imports and lack of inter-regional export oil pipeline capacity to higher-oil demand regions.  However, increased refining capacity near Denver has enabled local Colorado oil suppliers, including the Partnership, to receive pricing advantage over supplies located in less densely-populated northern Rocky Region areas.





Reliance on Managing General Partner





General.  As provided by the Agreement, PDC, as Managing General Partner, has authority to manage the Partnership’s activities through the D&O Agreement, utilizing its best efforts to carry out the business of the Partnership in a prudent and business-like fashion.  PDC has a fiduciary duty to exercise good faith and deal fairly with Investor Partners.  PDC’s executive staff manages the affairs of the Partnership, while technical geosciences and petroleum engineering staff oversee the well drilling, completions, recompletions, and operations. PDC’s administrative staff controls the Partnership’s finances and makes distributions, apportions costs and revenues among wells and prepares Partnership reports, financial statements and filings presented to Investor Partners, tax agencies and the SEC, as required.





Provisions of the D&O Agreement.  Under the terms of the D&O Agreement, the Partnership has authorized and extended to PDC the authority to manage the production operations of the natural gas and crude oil wells in which the Partnership owns an interest, including the initial drilling, testing, completion, and equipping of wells; subsequent additional Codell formation development, where economical, and ultimate evaluation for abandonment.  Further, the Partnership has the right to take in-kind and separately dispose of its share of all natural gas, NGLs and crude oil produced from the Partnership’s wells.  The Partnership designated PDC as its natural gas, NGLs and crude oil production marketing agent and authorized PDC to enter into and bind the Partnership, under those agreements PDC deems in the best interest of the Partnership, in the sale of the Partnership’s natural gas, NGLs and crude oil.  Generally, PDC has limited liability to the Partnership for losses sustained or liabilities incurred, except as may result from the operator's gross or willful negligence or misconduct.  PDC may subcontract certain functions as operator for Partnership wells but retains responsibility for work performed by subcontractors.  The D&O Agreement remains in force as long as any well or wells produce, or are capable of economic production, and for an additional period of 180 days from cessation of all production or until PDC is replaced as Managing General Partner as provided for in the D&O Agreement.





To the extent the Partnership has less than a 100% working interest in a well, Partnership obligations and liabilities are limited to its proportionate working interest share and thus, the Partnership paid only its proportionate share of total lease and development costs, pays only the Partnership’s proportionate share of operating costs, and receives its proportionate share of production subject only to royalties and overriding royalties.





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Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation.  The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the D&O Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations.  This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS.  These rates are reflective of similar costs incurred by comparable operators in the production field.  PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services or other services for the Partnership at the lesser of cost or competitive prices in the area of operations.





Operating Hazards and Insurance.  The Partnership's production operations include a variety of operating risks, including but not limited to fire, explosions, blowouts, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of natural gas.  The occurrence of any of these could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations.  The Partnership’s gathering and distribution operations are subject to the many hazards inherent in the industry.  These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.





Any significant problems related to the Partnership’s facilities could adversely affect the Partnership’s ability to conduct operations.  In accordance with customary industry practice, the Partnership maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability.  The occurrence of a significant event not fully insured against could materially adversely affect the Partnership’s operations and financial condition.  The Partnership cannot predict whether insurance will continue to be available at premium levels that justify purchase or whether insurance will be available at all.  Furthermore, the Partnership is not insured against economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or the Partnership’s inability to deliver natural gas.





PDC, in its capacity as operator, has purchased various insurance policies, including worker’s compensation, operator's bodily injury liability and property damage liability insurance, employer's liability insurance, automobile public liability insurance and operator's umbrella liability insurance and intends to maintain these policies subject to PDC's analysis of their premium costs, coverage and other factors.  During drilling operations, the Managing General Partner maintained public liability insurance of not less than $10 million; however, PDC may at its sole discretion in other situations, increase or decrease policy limits, change types of insurance and name PDC and the Partnership, individually or together, parties to the insurance as deemed appropriate under the circumstances, which may vary materially.  As operator of the Partnership's wells, PDC requires its subcontractors to carry liability insurance coverage with respect to the subcontractors’ activities.  PDC’s management, in its capacity as Managing General Partner, believes that in accordance with customary industry practice, adequate insurance, including insurance by PDC’s subcontractors, has been provided to the Partnership with coverage sufficient to protect the Investor Partners against the foreseeable risks of operation, drilling, additional Codell formation development and reworks and ongoing productions operations.  However, there can be no assurance that this insurance will be adequate to cover all losses or exposure for liability and thus, the occurrence of a significant event not fully insured against, could materially adversely affect Partnership operations and financial condition.  Furthermore, the Partnership is not insured against economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or the Partnership’s inability to deliver natural gas.  As of the date of this filing, the Managing General Partner has no knowledge that such events have occurred.





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Customers





PDC markets the natural gas, NGLs and crude oil from Partnership wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of the Partnership.  Currently, PDC sells Partnership natural gas in the Piceance Basin to Williams Production RMT (“Williams”), which has an extensive gathering and transportation system in this Basin.  In the Wattenberg Field, the natural gas and NGLs are sold primarily to DCP Midstream LP (“DCP”), which gathers and processes the gas and liquefiable hydrocarbons produced.  Natural gas and NGLs produced in Colorado may be impacted by changes in market prices on a national level, as well as changes in the market for natural gas within the Rocky Mountain Region.  Sales of natural gas and NGLs from the Partnership's wells to DCP and Williams are made on the spot market via open-access transportation arrangements through Williams or other pipelines and may be impacted by capacity interruptions on pipelines transporting natural gas out of the region.





The Partnership’s crude oil production is sold, at or near the Partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry, primarily as feedstock for refineries currently owned by Suncor, which are located north of Denver, Colorado.  Oil prices fluctuate not only with the general market for oil as may be indicated by changes in the New York Mercantile Exchange, or  NYMEX, but also due to changes in light-heavy crude oil supply and product demand-mix applicable to specific refining regions.





Number of total and full-time employees





The Partnership has no employees and relies on the Managing General Partner to manage the Partnership’s business.  PDC’s officers, directors and employees receive direct remuneration, compensation or reimbursement solely from PDC, and not the Partnership, with respect to their services rendered in their capacity to act on behalf of PDC, as Managing General Partner. See Item 11, Executive Compensation and Item 13, Certain Relationships and Related Transactions, and Director Independence for a discussion of compensation paid by the Partnership to the Managing General Partner.





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ITEM 1A.
RISK FACTORS





Not applicable.








ITEM 1B.
UNRESOLVED STAFF COMMENTS





None.








ITEM 2.
PROPERTIES





Information regarding the Partnership’s wells, production, proved reserves and acreage are included in Item 1, Business of this report and Note 2, Summary of Significant Accounting Policies, to the Partnership’s financial statements included in this report.








ITEM 3.
LEGAL PROCEEDINGS





The Registrant is not currently subject to any material pending legal proceedings.





See Note 7, Commitments and Contingencies to the accompanying financial statements for additional information related to litigation.








ITEM 4.
[REMOVED AND RESERVED]




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PART II





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





At December 31, 2010, the Partnership had 1,791 Investor Partners holding 4,470 units and one Managing General Partner.  The investments held by the Investor Partners are in the form of limited partnership interests.  Investor Partners' interests are transferable; however, no assignee of units in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner.  As of December 31, 2010, the Managing General Partner has repurchased no units of Partnership interests from Investor Partners.





Market.  There is no public market for the Partnership units nor will a public market develop for these units in the future.  Investor Partners may not be able to sell their Partnership interests or may only be able to sell their Partnership interest for less than fair market value.  No transfer of a unit may be made unless the transferee satisfies relevant suitability requirements, as imposed by federal and state law or the Partnership Agreement.  The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with applicable securities laws.  A sale or transfer of units by an individual investor partner requires PDC’s prior written consent.  For these and other reasons, an individual investor partner must anticipate that he or she may have to hold his or her partnership interests indefinitely and may not be able to liquidate his or her investment in the Partnership.  Consequently, an individual investor partner must be able to bear the economic risk of investing in the Partnership for an indefinite period of time.





Cash Distribution Policy.  PDC plans to make distributions of Partnership cash on a monthly basis, but no less often than quarterly, subject to funds being available for distribution.  PDC will make cash distributions of 63% of distributable cash to the Investor Partners, including any Investor Partner units purchased by the Managing General Partner, and 37% of distributable cash to the Managing General Partner, throughout the term of the Partnership.  Cash is distributed to the Investor Partners and PDC currently as a return of capital in the same proportion as their proportional interest in the net income of the Partnership.  Distributable cash, also referred to as distributable cash flows, has generally been the Partnership’s net cash flows provided by operating activities less any net cash used in investing activities.


PDC cannot presently predict amounts of future cash distributions, if any, from the Partnership.  However, PDC expressly conditions any and all future cash distributions upon the Partnership having sufficient cash available for distribution.  Sufficient cash available for distribution is defined generally as cash generated by the Partnership in excess of the amount the Managing General Partner determines is necessary or appropriate to provide for the conduct of the Partnership's business, to comply with applicable law, to comply with any other agreements or to provide for future distributions to unit holders.  In this regard, PDC reviews the accounts of the Partnership at least quarterly for the purpose of determining the sufficiency of distributable cash available for distribution.  Amounts will be paid to Investor Partners only after payment of fees and expenses to the Managing General Partner and its affiliates and only if there is sufficient cash available.





The ability of the Partnership to make or sustain cash distributions depends upon numerous factors.  PDC can give no assurance that any level of cash distributions to the Investor Partners of the Partnership will be attained, that cash distributions will equal or approximate cash distributions made to investor partners of prior drilling programs sponsored by PDC, or that any level of cash distributions can be maintained.  Fully developing all of the Partnership’s properties would require substantial capital expenditures.  Because of the restrictions set forth in the Agreement on making assessments on limited partnership units, the Partnership would generally be unable to fund such capital expenditures without bank borrowing or retaining all or a substantial portion of the Partnership’s cash flow.  At this time, the Managing General Partner does not anticipate electing to fund the initial or subsequent Codell formation refracturings or recompletions through bank borrowing.





Implementation of the Additional Codell Formation Development Plan would reduce or eliminate Partnership cash distributions to investors while the work is being conducted and paid for.  All funds withheld for the Additional Codell Formation Development Plan reduce the cash distributions to both the Managing General Partner and Investor Partners in the same proportion as their proportional interest in the net income of the Partnership.  These funds are held in the Partnership’s bank account which is included in the Partnership’s financial statements in “Cash and cash equivalents.”  The intended use of this cash is for executing the Additional Codell Formation Development Plan; however, if an unexpected operational need would arise, the funds retained may be used to fulfill this obligation.  The funds will be transferred to the Managing General Partner at the time these costs have been incurred.  If the Managing General Partner would determine to abandon or delay a significant portion of the Additional Codell Formation Development Plan, any funds which were withheld and not used for these Partnership activities would be distributed to the Managing General Partner and Investor Partners based on their proportional share.Depending upon the level of withholding and the results of operations, it is possible that investors could have taxable income from the Partnership without any corresponding distributions in future years.  If PDC were to be successful in the future acquisition effort of this Partnership, liquidation of the Partnership and a final payout would result in cessation of all future cash payments.  The exchange by an investor partner of limited partnership units for cash pursuant to any merger would be a taxable transaction for U.S. federal income tax purposes.  The effects of a potential acquisition may be different for each investor partner.  For more information concerning the Partnership’s Additional Codell Formation Development Plan see Item 1, Business – Operations, Drilling and Other Activities - Additional Codell Formation Development Plan.For additional information regarding PDC’s disclosed partnership acquisition intensions, refer to the section entitled Recent Developments−PDC Sponsored Drilling Program Acquisition Plan on page 3 and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−PDC Sponsored Drilling Program Acquisition Plan.





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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 and any potential merger.  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 and any potential merger.





The following table presents cash distributions made to the Partnership’s investors for the periods described:





Period

Cash

DistributionsFor the year ended December 31, 2010

$
14,355,892For the year ended December 31, 2009


34,262,653For the period from the Partnership's inception to December 31, 2010

$
76,965,008





The volume and rate of production from producing wells naturally declines with the passage of time and is generally not subject to the control of management.  The cash flow generated by the Partnership's activities and the amounts available for distribution to the Partnership's Investor Partners will, therefore, decline in the absence of significant increases in the prices that the Partnership receives for its natural gas, NGLs and crude oil production, or significant increases in the production of natural gas, NGLs and crude oil from the successful additional Codell formation development of these properties, if any.  The funds necessary for any additional Codell formation development would be withheld from the Partnership's distributable cash flows.  As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners would then decrease.  For more information regarding the additional Codell formation development of the Partnership’s Wattenberg Field wells see Item 1, Business−Operations, Drilling and Other Development Activities - Additional Codell Formation Development Planon page 6.  For more information concerning the Partnership’s cash flows from operations see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Liquidity and Capital Resources.





The Agreement permits the Partnership to borrow funds on its behalf for Partnership activities, exclusive of funds for the payment of cash distributions.  The Partnership may borrow needed funds from the Managing General Partner or from unaffiliated persons.  On loans or advances made available to the Partnership by the Managing General Partner, the Managing General Partner may not receive interest in excess of its interest costs, nor may the Managing General Partner receive interest in excess of the amounts which would be charged the Partnership (without reference to the Managing General Partner's financial abilities or guarantees) by unrelated banks on comparable loans for the same purpose.  At this time, the Managing General Partner does not anticipate electing to fund any of the Additional Codell Formation Development Plan activities through bank borrowings. (see Item 1, Business−Business Strategy, Development).  As the Partnership may have to pay interest on borrowed funds, the amount of Partnership funds available for distribution to the partners of the Partnership may be reduced accordingly.





Unit Repurchase Program.  Beginning in May 2011, the third anniversary of the date of the first Partnership distributions, Investor Partners may request that the Managing General Partner repurchase their respective limited partnership units.  The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production.  In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10% of the initial subscriptions if requested by an individual investor partner, subject to PDC’s financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the Partnership to be treated as a “publicly traded partnership” or result in the termination of the Partnership for federal income tax purposes.  If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis.





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In addition to the above repurchase program, individual investor partners periodically offer and PDC repurchases, units on a negotiated basis before the third anniversary of the date of the first cash distribution.  There have been no negotiated-basis limited partnership units repurchased by PDC as of December 31, 2010.








ITEM 6.
SELECTED FINANCIAL DATA





Not applicable.








ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS





The following discussion and analysis, as well as other sections in this Form 10-K, should be read in conjunction with the Partnership’s accompanying financial statements and related notes to the financial statements included in this report.  Further, the Partnership encourages the reader to revisit the Special Note Regarding Forward-Looking Statements on page one of the report.





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 August 2007 and operates 99 gross (97.9 net) productive wells located in the Rocky Mountain Region in the state of Colorado.  The Partnership drilled one additional well (1.0 net) which was declared to be a developmental dry hole due to downhole mechanical failure that was subsequently plugged and abandoned.  The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, 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.





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Recent Developments





PDC Sponsored Drilling Program Acquisition Plan





PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, beginning in the fall of 2010 and extending through the next three years, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of that partnership other than PDC or its affiliates (“non-affiliated Investor Partners”), in the limited partnerships that PDC has sponsored, including this Partnership.  For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships, refer to the disclosure included in Items 2.02, 7.01 and/or 8.01 of PDC’s Forms 8-K dated March 4, 2010, June 9, 2010, July 15, 2010 and November 17, 2010.  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 and the approval by a majority of the limited partnerships units held by the non-affiliated Investor Partners of each respective limited partnership.  Consummation of any proposed merger of a PDC sponsored limited partnership under the Acquisition Plan will likely result in the termination of the existence of that partnership and the right of non-affiliated Investor Partners to receive a cash payment for their limited partnership units in that partnership.




In December 2010, PDC acquired four affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership. PDC purchased these partnerships for the aggregate amount of $34.8 million.





In November 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership, and the 2005 Rockies Region Private Limited Partnership (collectively, the “2005 partnerships”).  PDC serves as the managing general partner of each of the 2005 partnerships.  Definitive proxy statements for each of the 2005 partnerships requesting approval for the applicable merger were mailed to the non-affiliated Investor Partners of the 2005 partnerships on February 7, 2011.  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 such partnership will merge with and into a wholly-owned subsidiary of PDC.  There is no assurance the partnerships will obtain the necessary approvals from non-affiliated investors.  PDC has re-evaluated the merger consideration agreed to in the merger agreements and has proposed to offer supplemental merger consideration to the non-affiliated Investor Partners of the 2005 partnerships in addition to the merger consideration described above.  On March 25, 2011, the special meeting of non-affiliated Investor Partners of the 2005 partnerships was adjourned until May 27, 2011.  PDC expects to send non-affiliated Investor Partners of the 2005 partnerships a proxy supplement that provides information relating to the increased merger consideration and also includes such Partnership’s year-end financial statements and the Partnership’s 2010 year-end reserve report.  Although there is no assurance of the likelihood or timing of the completion of the SEC proxy disclosure review process or whether each Partnership will obtain the necessary approvals from non-affiliated Investors Partners, PDC would expect to mail such proxy supplements to the non-affiliated Investors Partners of the 2005 partnerships in late April or early May.


The feasibility and timing of any future 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; 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 2005 partnerships, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur.





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 and 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 Wattenberg Field 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.





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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 recomplete or refracture the individual wells and to determine the timing of any additional Codell formation development activity.  The timing of the additional development can be affected by the desire to optimize the economic return by recompleting or refracturing 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 recompletions and refracturings have been at modeled economics; however, all recompletions or refracturings have not been economically successful and similar future development 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 recompletion or refracturing, 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 distributable cash flows.





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 development activities are funded in part through borrowing, potential distributable cash flows 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 withholding funds from several of the PDC sponsored partnerships, on a pro-rata basis allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, from distributable cash flows of the Partnership resulting from current production.  The funds retained are necessary for the Partnership to pay for additional Codell formation development costs and will materially reduce, up to 100%, distributable cash flows of the Partnership for a period of time not to exceed five years.  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.





Current estimated costs for these well refracturings and recompletions are between $175,000 and $240,000 per activity.  As of December 31, 2010, this Partnership has scheduled to complete 77 additional Codell formation development opportunities.  This increase from 75 potential additional Codell formation development opportunities as of December 31, 2009 is due to an increase in estimated future distributable cash flows based on current pricing and well economics.  Total withholding for these activities from the Partnership’s distributable cash flows 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.  As of December 31, 2010, $120,000 has been withheld from the Partnership distributions for these refracturings or recompletions.  Cumulatively, $370,000 has been withheld from Partnership distributions through February 28, 2011.





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Implementation of the Additional Codell Formation Development Plan would reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for.  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.





2010 and 2009 Partnership Overview





Natural gas, NGLs and crude oil sales decreased by $3.8 million for the 2010 annual period compared to 2009, primarily due to the production volume decline of 39% period-to-period, which was partially offset by the improved commodity price environment.  The average sales price per Mcfe, excluding the impact of realized derivative gains, was $4.99 during 2010 compared to $3.83 for 2009.  Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased to $6.18 during 2010 from $6.66 during 2009.  This decrease was primarily due to realized derivative gains from natural gas and crude oil sales contributing only $1.19 per Mcfe or $3.5 million to the 2010 total revenues as compared to $2.83 per Mcfe or $13.5 million to 2009 total revenues.  The Partnership’s 2010 revenues were favorably impacted by unrealized derivative gains on natural gas and crude oil sales of $4.7 million in 2010 as compared to unrealized losses of $18.6 million in 2009.





The Partnership’s combined natural gas, NGLs and crude oil production expenses and direct costs−administrative and general, increased by $0.1 million during the 2010 compared to 2009.  Production costs during 2010 were higher primarily due to higher lease operating costs and the non-recurring environmental remediation activities conducted during 2010, which were partially offset by the reduction of production volume-associated natural gas, NGLs and crude oil costs as well as the reduction in professional fees during 2010 compared to 2009.





The Partnership recorded an impairment loss of $27.7 million for the year ended December 31, 2010.  The impairment loss resulted from the downward revision to the future net cash flows of production activities in the Grand Valley Field in Colorado.  See Note 10, Impairment of Capitalized Costs to the accompanying financial statements for additional disclosure related to the Partnership’s proved property impairment.





Reporting on NGLs in 2010





As the Partnership embarks on the Additional Codell Formation Development Plan, the Managing General Partner believes that the NGLs will be an increased percentage of the Partnership’s total revenues and production volumes in future years.  Additionally, as a result of a computer system upgrade during the second half of 2009, the Managing General Partner was able to accumulate the Partnership’s NGLs sales revenues and production volumes for 2010.  Prior to the system upgrade, the Partnership’s NGLs sales revenues and production volumes were included in the natural gas sales revenues and production volume statistical information.  The NGLs are extracted by third-party purchasers, from the Partnership’s natural gas production, after delivery.  To provide additional information to the reader, the Partnership has shown all of the NGLs revenue and production volume statistical data separately for 2010.  For comparability when discussing 2010 results with 2009, the Partnership has added the 2010 NGLs sales revenue and natural gas equivalent production volumes with the relevant 2010 natural gas activity data and compared it to the 2009 natural gas results.  Reporting the Partnership’s information in this fashion, gives comparability to readers when discussing the Partnership’s year to year results and provides more detailed information which may be beneficial for understanding the Partnership’s current business.  Starting in the first quarter of 2011, all of the Partnership’s revenues and production volumes of natural gas, NGLs and crude oil will be presented in a fashion comparable to the 2010 information contained in this report.





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Results of Operations





Summary Operating Results





The following table presents selected information regarding the Partnership’s results of operations.  Prior to 2010, NGLs were included in natural gas, which impacts the comparability of natural gas production, natural gas sales and natural gas average sales price for 2010 to 2009.  However, total Mcfe production, total sales and Mcfe average price is comparable.  See the previous discussion in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Reporting on NGLs in 2010 for additional details.





Year Ended December 31,2010


2009


ChangeNumber of producing wells (end of period)


99



99



-Production(1)Natural gas (Mcf)


2,243,886



3,901,423



-42
%NGLs (Bbl)


29,497



-



*Subtotal natural gas and NGLs (Mcfe)(2)


2,420,868



3,901,423



-38
%Crude oil (Bbl)


80,530



143,721



-44
%Natural gas equivalents (Mcfe)(2)


2,904,048



4,763,749



-39
%Mcfe per day


7,956



13,051



-39
%Natural Gas, NGLs and Crude Oil SalesNatural gas

$
7,842,626


$
10,378,462



-24
%NGLs


785,262



-



*Subtotal natural gas and NGLs


8,627,888



10,378,462



-17
%Crude oil


5,861,127



7,882,474



-26
%Total natural gas, NGLs and crude oil sales

$
14,489,015


$
18,260,936



-21
%Realized Gain on Derivatives, netNatural gas

$
2,211,186


$
9,521,628



-77
%Crude oil


1,258,230



3,948,893



-68
%Total realized gain on derivatives, net

$
3,469,416


$
13,470,521



-74
%Average Selling Price (excluding realized gain on derivatives)Natural gas (per Mcf)

$
3.50


$
2.66



31
%NGLs (per Bbl)


26.62



-



*Natural gas and NGLs (per Mcfe)


3.56



2.66



34
%Crude oil (per Bbl)


72.78



54.85



33
%Natural gas equivalents (per Mcfe)


4.99



3.83



30
%Average Selling Price (including realized gain on derivatives)Natural gas (per Mcf)

$
4.48


$
5.10



-12
%NGLs (per Bbl)


26.62



-



*Natural gas and NGLs (per Mcfe)


4.48



5.10



-12
%Crude oil (per Bbl)


88.41



82.32



7
%Natural gas equivalents (per Mcfe)


6.18



6.66



-7
%Average cost per McfeNatural gas, NGLs and crude oil production cost(3)

$
1.74


$
0.97



80
%Depreciation, depletion and amortization


3.26



3.27



0
%Operating costs and expenses:Direct costs - general and administrative

$
200,907


$
496,788



-60
%Depreciation, depletion and amortization

$
9,456,143


$
15,554,781



-39
%Loss on impairment of natural gas and crude oil properties

$
27,687,418


$
-



*Cash distributions

$
14,355,892


$
34,262,653



-58
%





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


_______________


(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)
A ratio of energy content of natural gas, NGLs and crude oil (six Mcf of natural gas equals one Bbl of crude oil or NGL) was used to obtain a conversion factor to convert NGLs and crude oil production into equivalent Mcf of natural gas.


(3)
Production costs represent natural gas, NGLs and crude oil operating expenses which include production taxes.





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Natural Gas, NGLs and Crude Oil Sales





Changes in Natural Gas, NGLs and Crude Oil Production Volumes.  For the 2010 annual period compared to the 2009 annual period, natural gas, NGLs and crude oil production, on an energy equivalency-basis, decreased 39%, primarily due to steeper than normal production declines for this stage in the wells’ production life cycle at the Partnership’s Grand Valley Field wells in addition to operational constraints at Wattenberg Field Partnership wells.  Additionally, Grand Valley Field well equipment problems, requiring well workovers of seven wells, also contributed to the production volume decline during the current period.





Changes in Natural Gas and NGLs Sales.  During 2010, the Partnership began separate reporting of NGL sales, which were previously classified and reported as a component of natural gas sales revenues.  Combined 2010 natural gas and NGL sales were $1.8 million, or 17% lower than comparably reported 2009 natural gas sales revenues.  Combined production from natural gas and NGLs were 2,420,868 Mcfe in 2010 compared to 3,901,423 Mcfe in 2009.  This 1,480,555 Mcfe or 38% reduction in production was partially offset by the higher average selling price for these commodities of $3.56 per Mcfe in 2010 compared to $2.66 in 2009.  This $0.90 per Mcfe increase represents a 34% overall price increase from the prior year.





Changes in Crude Oil Sales.  The $2.0 million, or 26% decrease in crude oil sales for the 2010 annual period as compared to the 2009 annual period, was primarily a reflection of the production volume decrease of 44%, which was partially offset by a higher average sales price per Bbl of 33%.  The average sales price per Bbl, excluding the impact of realized derivative gains, was $72.78 for the current year annual period compared to $54.85 for the same period a year ago.





Natural Gas, NGLsand Crude Oil Pricing.   The Partnership’s results of operations depend upon many factors, particularly the price of natural gas, NGLs and crude oil and on PDC’s ability to market the Partnership’s production effectively.  Natural gas, NGLs and crude oil prices are among the most volatile of all commodity prices.  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, and the supply and demand relationships in that region or locality and availability of sufficient pipeline capacity.  This can be especially true in the Rocky Mountain Region.  The combination of increased drilling activity and the lack of local markets have 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 and transportation capacity beyond the Partnership’s control.  Crude oil pricing is driven predominantly by the physical market, supply and demand, the financial markets and politics.





The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby regional prices.  The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has 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, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets.  This negative differential has narrowed in the last few years and is lower than historical variances.  The negative differential between NYMEX and CIG averaged $0.47 and $0.92 for 2010 and 2009, respectively.





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Commodity Price Risk Management, Net





Commodity price risk management, net, includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to the Partnership’s natural gas and crude oil production.  See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to the Partnership’s 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 gain (loss), net.





Year Ended December 31,Commodity price risk management, net

2010


2009Realized gainNatural Gas

$
2,211,186


$
9,521,628Crude Oil


1,258,230



3,948,893Total realized gain, net


3,469,416



13,470,521Unrealized gain (loss)Reclassification of realized gain included inprior periods unrealized


(519,880
)


(12,096,419
)Unrealized gain (loss) for the period


5,200,995



(6,487,808
)Total unrealized gain (loss), net


4,681,115



(18,584,227
)Commodity price risk management gain (loss), net

$
8,150,531


$
(5,113,706
)





Realized gains recognized in 2010 and 2009 are a result of lower natural gas and crude oil spot prices at settlement compared to the respective strike price, offset in part by the negative basis differential between NYMEX and CIG being narrower than the strike price of the Partnership’s derivative position.  During 2010, the Partnership recorded unrealized gains of $5.9 million on the Partnership’s natural gas and crude oil positions that were partially offset by unrealized losses on its CIG basis swaps of $0.7 million, as the forward basis differential between NYMEX and CIG had continued to narrow from the prior year.





During 2009, the Partnership recorded unrealized losses on its CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow from the prior year along with unrealized losses on the Partnership’s crude oil positions, offset by unrealized gains on the Partnership’s natural gas positions.





Natural Gas and Crude Oil Sales Derivative Instruments.  The Partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices.  The Partnership has in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of the Partnership’s estimated natural gas and crude oil production.  Because the Partnership sells its physical natural gas and crude oil at similar prices to the indexes inherent in the Partnership’s derivative instruments, 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.  See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to the Partnership’s financial statements included in this report on how each derivative type impacts the Partnership’s cash flows and detailed presentation of the Partnership’s derivative positions as of December 31, 2010.





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The following table presents the Partnership’s derivative positions in effect as of December 31, 2010.





Collars


Fixed-Price Swaps


CIG Basis Protection SwapsCommodity/

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

December 31,

2010(2)Floors


CeilingsNatural GasCIG01/01 - 03/31/2011


207,438


$
4.75


$
9.45



-


$
-



-


$
-


$
161,047NYMEX01/01 - 03/31/2011


67,527



5.75



8.30



152,488



6.82



220,015



(1.88
)


142,93504/01 - 06/30/2011


-



-



-



414,885



6.78



414,885



(1.88
)


399,41607/01 - 09/30/2011


-



-



-



401,561



6.73



401,561



(1.88
)


314,53810/01 - 12/31/2011


-



-



-



384,547



6.78



384,547



(1.88
)


197,5382012


86,330



6.00



8.27



1,315,943



6.98



1,402,282



(1.88
)


613,3952013


-



-



-



1,238,582



7.12



1,238,582



(1.88
)


518,755Total Natural Gas


361,295











3,908,006







4,061,872







2,347,624Crude OilNYMEX01/01 - 03/31/2011


-



-



-



7,109



70.75



-



-



(147,645
)04/01 - 06/30/2011


-



-



-



7,028



70.75



-



-



(155,762
)07/01 - 09/30/2011


-



-



-



6,977



70.75



-



-



(157,734
)10/01 - 12/31/2011


-



-



-



6,929



70.75



-



-



(156,863
)Total Crude Oil


-











28,043







-







(618,004
)Total Natural Gas and Crude Oil





























$
1,729,620





(1)
A standard unit of measure for natural gas (one MMBtu equals one Mcf).


(2)
As of December 31, 2010, approximately 5% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3).





Natural Gas, NGLs and Crude Oil Production Costs





Natural gas, NGLs and crude oil production costs include production taxes and transportation costs which vary with revenues and production, well operating costs charged on a per well basis and other direct costs incurred in the production process. As production declines, fixed costs increase as a percentage of total costs resulting in production costs per unit increases.  Typically, as production is expected to continue to decline, production costs per unit can be expected to increase in the future until such time as the Partnership successfully recompletes the Wattenberg Field wells.





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 and service rig workovers.





Changes in natural gas, NGLsand crude oil production expenses.Production and operating costs for 2010 increased by $0.4 million compared to 2009 due to higher lease operating costs as a result of the workover of 10 Partnership wells.  Additionally, 2010 well operations costs were higher as a result of the increase in the per well operations fee charged by the Managing General Partner, consistent with the terms of the D&O Agreement as well as the nonrecurring recognition of environmental remediation expenditures of $0.1 million, which includes an accrual for environmental remediation expenditures of $5,000.  These production cost increases were partially offset by reductions in volume-associated natural gas, NGLs and crude oil production costs including production taxes, natural gas transportation and lease operating expenses due to the production volume declines previously noted in the section, Natural Gas, NGLs and Crude Oil Sales.  Production and operating costs per Mcfe rose to $1.74 during 2010 compared to $0.97 for 2009 due to the effect of higher per-well related expenditures offset by lower per-volume related natural gas, NGLs and crude oil production costs.





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Direct Costs−General and Administrative





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 decreased during the 2010 annual period compared to the 2009 annual period, by approximately $0.3 million principally due to decreased fees for professional services.





Depreciation, Depletion and Amortization





Natural gas and crude oil properties.  Depreciation, depletion and amortization (DD&A) expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes.  DD&A expense is primarily based upon year-end proved developed producing reserves.  The pricing measurement for reserve estimations is a 12-month average of the first day of the month price for each month in the period.  If prices increase, the estimated volumes of proved reserves will increase, resulting in decreases in the rate of DD&A per unit of production.  If prices decrease, the estimated volumes of proved reserves will decrease, resulting in increases in the rate of DD&A per unit of production.





Changes in DD&A expense.  The DD&A expense rate per Mcfe decreased to 3.26 for 2010 compared to $3.27 for 2009.  The decrease in the per Mcfe rate for 2010 compared to 2009, is partially the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley fields, which have significantly different DD&A rates that was offset by the field-level depletion rate changes due to reserve revisions at December 31, 2009.  The 2009 downward revision of proved developed producing reserves in the Partnership’s Grand Valley Field was partially offset by the upward revision of proved developed producing reserves in the Partnership’s Wattenberg Field.  This stable DD&A expense rate combined with the effect of the production declines noted in previous sections, resulted in a decreased DD&A expense of approximately $6.1 million for 2010 compared to 2009.





Loss on Impairment of Natural Gas and Crude Oil Properties





The Partnership assesses its proved natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold.  The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event.  Therefore, impairment tests are completed as of December 31 each year.  The estimates of future prices may differ from current market prices of natural gas and crude oil.  Certain events, including but not limited to, downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership’s proved natural gas and crude oil properties.  If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, as occurred for the year ended December 31, 2010, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value.  The Partnership’s estimated production used in the impairment testing is taken from the annual reserve report (See Supplemental Natural Gas, NGL and Crude Oil Information –Unaudited—Net Proved Reserves).  Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date.  Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves.  A decline in the forward price curves used to estimate future cash flows at December 31, 2010 accompanied by lower reserves reflected in the Partnership’s annual reserve report resulted in an impairment in the fourth quarter of 2010.  This downward revision to the future net cash flows resulted primarily from an 8,034 or 33.5% decrease in future estimated MMcfs of natural gas production due to well economics and a reduction in prices from 2009.  The Partnership recorded an impairment loss, the first natural gas and oil properties impairment recognized by the Partnership since it began operations in 2007, of $27.7 million for the year ended December 31, 2010.  The impairment loss resulted from the downward revision to the fair value of discounted future net cash flows of production activities in the Grand Valley Field in Colorado.





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Financial Condition





Capital Resources and Liquidity





The Partnership’s primary sources of cash for both the 2010 and the 2009 annual periods 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 cost, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner.  Fluctuations in the Partnership’s operating cash flow 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 Partnership 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 December 31, 2010, the Partnership had natural gas and crude oil derivative positions in place covering 90% of expected natural gas production and 45% of expected oil production for 2011, at an average price of $4.83 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 2009 comparative period which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2010 and 2009.  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 refracturing and recompletion activities which are more fully described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Additional Codell Formation Development Plan.





Working Capital





The Partnership had working capital at December 31, 2010 of $2.9 million compared to working capital of $4.6 million at December 31, 2009, a decrease of approximately $1.7 million.  This decrease was primarily due to the following:





·
Cash and cash equivalents increased by $0.7 million between December 31, 2010 and December 31, 2009.


·
Accounts receivable decreased by $1.1 million between December 31, 2010 and December 31, 2009.


·
Realized derivative gains receivables decreased by $1.2 million between December 31, 2010 and December 31, 2009.


·
Net short-term unrealized derivative gains receivable increased by $0.1 million between December 31, 2010 and December 31, 2009.


·
Due to the Managing General Partner-other payable, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, increased by approximately $0.2 million as of December 31, 2010 compared to December 31, 2009.





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Working capital, primarily cash and cash equivalents, is expected to increase during early 2011 due to cash flows from operations and the Partnership’s anticipated withholding of cash from the Managing General Partner and Investor Partners, on a pro-rata basis, for the initial additional Codell formation development activities.  This withholding began in the fourth quarter of 2010 with the withholding of $120,000.  Cash will begin to decrease as the funds are utilized in payment of the completed development activities, currently planned to occur during 2012. Funding for the Additional Codell Formation Development Plan will be provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners on a percentage of Partnership ownership pro-rata basis.  Working capital is expected to similarly fluctuate by increasing during periods of Additional Codell Formation Development Plan funding and by decreasing during periods when payments are made for completed refracturing or recompletion.





Cash Flows





Cash Flows From Operating Activities





Net cash provided by operating activities was $15.1 million for 2010 compared to $33.5 million for 2009, a decrease of approximately $18.4 million.  This decrease in cash provided by operating activities was due primarily to the following:





·
A decrease in direct costs-general and administrative of $0.3 million, or 60%;


·
A decrease in natural gas, NGLs and crude oil sales receipts of $8.1 million, or 34%, accompanied by a decrease in commodity price risk management realized gains receipts of $11.8 million, or 72%, and an increase in natural gas, NGLs and crude oil production costs of $0.4 million, or 9%; and


·
An increase in Due to Managing General Partner-other, net, receipts of approximately $1.6 million, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains.





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 additional Codell formation development 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.





Cash Flows From Investing Activities





During 2010, the Partnership invested $0.1 million for additional equipment that supports treatment, delivery and measurement of natural gas and crude oil or environmental protection.  After the completion of the Partnership’s drilling activities, the Partnership incurred approximately $0.6 million during 2009, for natural gas and oil development reclamation in order to restore well pad and access road site stability and ecosystem functions.





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Cash Flows From Financing Activities





The Partnership initiated monthly cash distributions to investors in May 2008 and has distributed $77.0 million through December 31, 2010.  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 and include amounts distributed to PDC for limited partnership units repurchased.





Year

Ended

Managing

General Partner

Distributions


Investor

Partners

Distributions


Total

Distributions2010

$
5,311,680


$
9,044,212


$
14,355,8922009

$
12,906,991


$
21,355,662


$
34,262,653




The decrease in total distributions for 2010 as compared to 2009 is primarily due to the significant decrease in cash flows from operating activities during these respective years.





Additionally, the Partnership began funding for the Additional Codell Formation Development Plan during October 2010.  As of December 31, 2010, on a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $44,400 and $75,600, respectively, from the Managing General Partner’s and Investor Partners’ share of distributable cash flows.  These and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing or recompletion costs to be incurred during 2012, and thereafter and are expected to decrease distributions from the 2009 levels for the next several years.  For additional information, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Additional Codell Formation Development Plan.





Critical Accounting Policies and Estimates





The Managing General Partner has identified the following policies as critical to business operations and the understanding of the results of the operations of the Partnership.  The following is not a comprehensive list of all of the Partnership’s accounting policies.  In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States, with no need for management's judgment in their application.  There are also areas in which management's judgment in selecting any available alternative would not produce a materially different result. However, certain of the Partnership’s accounting policies are particularly important to the portrayal of the Partnership's financial position and results of operations and the Managing General Partner may use significant judgment in their application; as a result these policies are subject to inherent degree of uncertainty.  In applying these policies, the Managing General Partner uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates.  Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate.  For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies in the accompanying financial statements.  The Partnership's critical accounting policies and estimates are as follows:





Natural Gas and Crude Oil Properties





The Partnership accounts for its natural gas and crude oil properties under the successful efforts method of accounting.  Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves.  Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves.





Annually, the Managing General Partner engages an independent petroleum engineer to prepare a reserve and economic evaluation of the Partnership’s properties on a well-by-well basis as of December 31.  The process of estimating and evaluating natural gas, NGLs and crude oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data.  The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions.  As a result, revisions in existing reserve estimates occur from time to time.  Although every reasonable effort is made to ensure that reserve estimates reported represent the Managing General Partner’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time.  Because estimates of reserves significantly affect the Partnership’s DD&A expense, a change in the Partnership’s estimated reserves could have an effect on its net income.





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Proved developed reserves are those natural gas, NGLs and crude oil quantities expected to be recovered from currently producing zones under the continuation of present operating methods.  Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development.





The Partnership assesses its natural gas and crude oil properties for possible impairment by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates commodities to be sold.  The estimates of future prices may differ from current market prices of natural gas, NGLs and crude oil.  Any downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future net cash flows and an impairment of the Partnership’s natural gas and crude oil properties.  Although the Partnership’s cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  See Note 10, Impairment of Capitalized Costs to the accompanying financial statements for additional disclosure related to the Partnership’s proved property impairment.





Natural Gas, NGLs and Crude Oil Sales Revenue Recognition





Natural gas, NGLs and crude oil sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured.  The Partnership records sales revenue based on an estimate of the volumes delivered at prices tied to market indexes, adjusted based on agreed upon contract terms.  The Managing General Partner estimates the Partnership’s sales volumes based on the Managing General Partner’s measured volume readings.  The Managing General Partner then adjusts the Partnership’s natural gas, NGL and crude oil sales in subsequent periods based on the data received from the Partnership’s purchasers that reflects actual volumes received.  The Partnership receives payment for sales from one to three months after actual delivery has occurred.  The differences in sales estimates and actual sales are recorded up to two months later.  Historically, differences have been immaterial.





Fair Value of Financial Instruments





Determination of Fair Value.  The Partnership’s fair value measurements are estimated pursuant to a fair value hierarchy that requires the Managing General Partner to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels.  The three levels of inputs that may be used to measure fair value are defined as:





·
Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.  Included in Level 1 are the Partnership’s commodity derivative instruments for NYMEX-based natural gas swaps.





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·
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.  Included in Level 3 are the Partnership’s commodity derivative instruments for CIG-based natural gas swaps, crude oil swaps, natural gas and crude oil collars, and the Partnership’s natural gas basis protection derivative instruments.





Derivative Financial Instruments.  The Managing General Partner measures fair value of the Partnership’s derivatives based upon quoted market prices, where available.  The Managing General Partner’s valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) 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.  The methods described above may produce a fair value calculation that may not be indicative of future fair values.  The Managing General Partner’s valuation determination also gives consideration to the nonperformance risk on PDC’s own liabilities as well as the credit standing of derivative instrument counterparties.  The Managing General Partner primarily uses financial institutions as counterparties to its derivative contracts.  The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  The Managing General Partner has determined based on this evaluation, that the impact of nonperformance of the Partnership’s counterparties on the fair value of the Partnership’s derivative instruments is insignificant.  Furthermore, while the Managing General Partner believes these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.





Recent Accounting Standards





See Note 2, Summary of Significant Accounting Policies to the accompanying financial statements included in this Annual Report, for recently issued and implemented accounting standards.








ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK





Not applicable.








ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA





The response to this Item is set forth herein in a separate section of this report, beginning at page F-1.








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





None.




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ITEM 9A.
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 December 31, 2010, 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 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 the Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.





Based upon the evaluation, the Managing General Partner’s Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, 2010.





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





Management of PDC, the Managing General Partner of the Partnership, is responsible for establishing and maintaining adequate internal control over financial reporting.  Internal control over financial reporting is defined in Exchange Act Rules 13a-15(f) and 15d-15(f) as a process designed by, or under the supervision of, the issuer’s principal executive and principal financial officers, or persons performing similar functions, and effected by the issuer’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:





(1)
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;





(2)
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and





(3)
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer’s assets that could have a material effect on the financial statements of the issuer.





Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.





Management of the Managing General Partner has assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2010, based upon the criteria established in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on this evaluation, management of the Managing General Partner concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2010.





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





(c)  Other Changes in Internal Control over Financial Reporting





PDC, the Managing General Partner, made no changes during the quarter ended December 31, 2010 in the Partnership’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.








ITEM 9B.
OTHER INFORMATION





None.





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PART III





ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE





The Partnership has no employees of its own and has authorized the Managing General Partner to manage the Partnership’s business through the D&O Agreement.  PDC’s directors and executive officers and other key employees receive direct remuneration, compensation or reimbursement solely from PDC, and not the Partnership, with respect to services rendered in their capacity to act on behalf of the Partnership.





Board Management and Risk Oversight





PDC, a publicly-owned Nevada corporation, was organized in 1955.  The common stock of PDC is traded on the NASDAQ Global Select Market under the symbol "PETD."  The business and affairs of the Partnership are managed by the Managing General Partner through the D&O Agreement, by or under the direction of PDC’s Board of Directors (the “Board”), in accordance with Nevada law and PDC’s By-Laws. The directors’ fiduciary duty is to exercise their business judgment in the best interests of PDC’s shareholders, and in that regard, as Managing General Partner, the best interests of the Partnership and other sponsored drilling partnerships.  The Board has adopted Corporate Governance Guidelines that govern the structure and functioning of the Board and establish the Board’s policies on a number of corporate governance issues.  With respect to the separation of the offices of Chairman and Chief Executive Officer, or CEO, the Board believes it is most prudent to address this issue as a part of its succession planning process and to make a final determination based on the facts and circumstances at the time of the Chairman’s election, annually or as circumstances warrant.





The Managing General Partner’s Board seeks to understand and oversee critical business risks.  Risks are considered in every business decision, not just through Board oversight of the Managing General Partner’s Risk Management system.  The Board realizes, however, that it is not possible to eliminate all risk, nor is it desirable, and that appropriate risk-taking is essential to achieve the Managing General Partner’s objectives.  The Board risk oversight structure provides that management report on critical business risk issues to the Planning and Finance Committee, which includes in part, an oversight function concerning PDC’s liquidity, operational and credit risk management.  In this regard, the Planning and Finance Committee also provides similar risk assessment and management process oversight functions for sponsored drilling program partnerships, which includes the Partnership.  Other Board committees, however, are active in managing the risks related to such committee’s oversight areas.  For example, the Audit Committee reviews many risks and related controls in areas that it considers fundamental to the integrity and reliability for the PDC’s financial statements, such as counterparty risks and derivative program risks.  The Managing General Partner’s Board has established the Audit Committee, including a subcommittee which focuses specifically on financial reporting matters of PDC’s sponsored drilling partnerships, to assist the Board in monitoring not only the integrity of the Managing General Partner’s financial reporting systems and internal controls but also PDC’s legal and regulatory compliance.  The Board has created a Special Committee that has considered, upon Board request, the potential repurchase of certain of the sponsored drilling partnerships for which PDC serves as Managing General Partner.  The Special Committee has not been asked to consider a repurchase of Rockies Region 2007 Limited Partnership at this time.





Managing General Partner Duties and Resource Allocation





As the Managing General Partner, PDC actively manages and conducts the business of the Partnership under the authority of the D&O Agreement.  PDC’s executive officers are full-time employees who devote the entirety of their daily time to the business and operations of PDC.  Included in each executive’s responsibilities to PDC is a time commitment, as may be reasonably required of their expertise, to conduct the primary business affairs of the Partnership that include the following:





·
Profitable development and cost-effective production operations of the Partnership’s reserves;


·
Market-responsive natural gas and crude oil marketing and prudent field operations cost management which support maximum cash flows; and


·
Technology-enhanced compliant Partnership administration including the following: accounting; revenue and cost allocation; cash management; tax and regulatory agency reporting and filing; and Investor Partner relations.





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Although the Partnership has not adopted a formal Code of Ethics, the Managing General Partner, has implemented a Code of Business Conduct and Ethics, as amended (“the Code of Conduct”) that applies to all Directors, officers, employees, agents and representatives of the Managing General Partner and consultants.  The Managing General Partner’s principal executive officer, principal financial officer and principal accounting officer are subject to additional specific provisions under the Code of Conduct.  The Managing General Partner’s Code of Conduct is posted on PDC’s website at www.petd.com.





The Corporate Governance section of the Managing General Partner’s internet site contains additional information, including By-Laws, written charters for each Board committee and Board corporate governance guidelines.  PDC's internet address is www.petd.com.  PDC will make available to Investor Partners audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods.  PDC also posts these audited financial statements filed with the SEC, on its internet site.








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Petroleum Development Corporation (dba PDC Energy)





The executive officers and directors of PDC, their principal occupations for the past five years and additional information is set forth below:





Name

Age

Positions and

Offices Held

Director

Since

Directorship

Term ExpiresRichard W McCullough

59

Chairman and Chief Executive Officer

2007

2013Gysle R. Shellum

59

Chief Financial Officer

-

-R. Scott Meyers

36

Chief Accounting Officer

-

-Barton R. Brookman, Jr.

48

Senior Vice President Exploration and Production

-

-Daniel W. Amidon

50

General Counsel and Secretary

-

-Lance Lauck

48

Senior Vice President Business Development

-

-Joseph E. Casabona

67

Director

2007

2011Anthony J. Crisafio

58

Director

2006

2012Larry F. Mazza

50

Director

2007

2013David C. Parke

44

Director

2003

2011Jeffrey C. Swoveland

56

Director

1991

2011James M. Trimble

62

Director

2009

2013Kimberly Luff Wakim

52

Director

2003

2012


Richard W. McCulloughwas appointed Chief Executive Officer of the Company in June 2008 and Chairman of PDC’s Board of Directors in November 2008. From November 2006 until November 2008, he served as the Chief Financial Officer of the Company. Prior to joining PDC, Mr. McCullough served from July 2005 to November 2006 as an energy consultant. From January 2004 to July 2005, he was President and Chief Executive Officer of Gasource, LLC, a marketer of long-term, natural gas supplies in Dallas, Texas. From 2001 to 2003, Mr. McCullough served as an investment banker with J.P. Morgan Securities, Atlanta, Georgia, in the public finance utility group supporting bankers nationally in all natural gas matters. Additionally, Mr. McCullough has held senior positions with Progress Energy, Deloitte and Touche, and the Municipal Gas Authority of Georgia. He holds BS and MS degrees from the University of Southern Mississippi and was a practicing Certified Public Accountant for eight years.  Mr. McCullough serves as Chairman of the Executive Committee and serves on the Planning and Finance Committee.





Gysle R. Shellumwas appointed Chief Financial Officer in 2008. Prior to joining the Company, Mr. Shellum served as Vice President, Finance and Special Projects of Crosstex Energy, L.P., Dallas, Texas. Mr. Shellum served in this capacity from September 2004 through September 2008. From March 2001 until September 2004, Mr. Shellum served as a consultant to Value Capital, a private consulting firm in Dallas, Texas, where he worked on various projects, including corporate finance and Sarbanes-Oxley Act compliance. Crosstex Energy, L.P. is a publicly traded Delaware limited partnership whose securities are listed on the NASDAQ Global Select Market and is an independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids.





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R. Scott Meyerswas appointed Chief Accounting Officer on April 2, 2009.  Prior to joining PDC, Mr. Meyers served as a Senior Manager with Schneider Downs Co., Inc., an accounting firm based in Pittsburgh, Pennsylvania.  Mr. Meyers served in such capacity from April 2008 to March 2009.  Prior thereto, from November 2002 to March 2008, Mr. Meyers was employed by PricewaterhouseCoopers LLP, the last two and one-half years serving as Senior Manager.
 
 Barton R. Brookman, Jr. was appointed Senior Vice President Exploration and Production in March 2008. Previously, Mr. Brookman served as Vice President Exploration and Production since joining PDC in July 2005. Prior to joining PDC, Mr. Brookman worked for Patina Oil and Gas and its predecessor Snyder Oil for 17 years in a series of positions of increasing responsibility, ending his service as Vice President of Operations of Patina.
 
 Daniel W. Amidonwas appointed General Counsel and Secretary in July 2007. Prior to his current position, Mr. Amidon was employed by Wheeling-Pittsburgh Steel Corporation beginning in July 2004; he served in several positions including General Counsel and Secretary. Prior to his employment with Wheeling-Pittsburgh Steel, Mr. Amidon worked for J&L Specialty Steel Inc. from 1992 through July 2004 in positions of increasing responsibility, including General Counsel and Secretary. Mr. Amidon practiced with the Pittsburgh law firm of Buchanan Ingersoll PC from 1986 through 1992.
 
 Lance Lauckwas appointed Senior Vice President Business Development in August 2009.  Previously Mr. Lauck served as Vice President - Acquisitions and Business Development for Quantum Resources Management LLC from 2006 - 2009. From 1988 until 2006, he held various management positions at Anadarko Petroleum Corporation in the areas of acquisitions and divestitures, corporate mergers and business development.
 
 Joseph E. Casabona served as Executive Vice President and member of the Board of Directors of Denver-based Energy Corporation of America, a natural gas exploration and development company, from 1985 until his retirement in May 2007. Mr. Casabona’s responsibilities included strategic planning as well as executive oversight of drilling operations in the continental U.S. and internationally. From 2008 through 2010, Mr. Casabona served as Chief Executive Officer of Paramax Resources Ltd, a junior public Canadian oil & gas company (PMXRF) engaged in the business of acquiring and exploration of oil and gas prospects, primarily in Canada and Idaho. Mr. Casabona serves as Chairman of the Planning and Finance Committee and serves on the Audit Committee.
 
 Anthony J. Crisafio, a Certified Public Accountant, has served as an independent business consultant for more than fifteen years, providing financial and operational advice to businesses in a variety of industries and stages of development. He also serves as an interim Chief Financial Officer and Advisory Board member for a number of privately held companies and has been a Certified Public Accountant for more than thirty years. Mr. Crisafio served as the Chief Operating Officer, Treasurer and member of the Board of Directors of Cinema World, Inc. from 1989 until 1993. From 1975 until 1989, he was employed by Ernst & Young and was a partner with Ernst & Young from 1986 to 1989. He was responsible for several Securities and Exchange Commission (“SEC”) registered client engagements and gained significant experience with oil and gas industry clients and mergers and acquisitions. Mr. Crisafio serves as the Chairman of the Audit Committee and serves on the Compensation Committee.
 
 Larry F. Mazza is President and Chief Executive Officer of MVB Bank, Inc. in Fairmont, West Virginia. He has been Chief Executive Officer since March 2005, and added the duties of President in January of 2009. Prior to 2005, Mr. Mazza served as Senior Vice President Retail Banking for BB&T and its predecessors in West Virginia, where he was employed from June 1986 to March 2005. A Certified Public Accountant for 26 years, Mr. Mazza also was previously an auditor with KPMG. Mr. Mazza serves on the Nominating and Governance Committee and the Compensation Committee.
 
 David C. Parke is a Managing Director in the investment banking group of Boenning & Scattergood, Inc., West Conshohocken, Pennsylvania, a full-service investment banking firm.  Prior to joining Boenning & Scattergood in November 2006, he was a Director with Mufson Howe Hunter & Company LLC, Philadelphia, Pennsylvania, an investment banking firm, from October 2003 to November 2006.  From 1992 through 2003, Mr. Parke was Director of Corporate Finance of Investec, Inc. and its predecessor Pennsylvania Merchant Group Ltd., investment banking companies.  Prior to joining Pennsylvania Merchant Group, Mr. Parke served in the corporate finance departments of Wheat First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, Inc., now part of Stifel Nicolaus.  Mr. Parke serves on the Planning and Finance Committee, the Compensation Committee and on the Nominating and Governance Committee.





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Jeffrey C. Swoveland is President and Chief Executive Officer of ReGear Life Sciences, Inc. in Pittsburgh, Pennsylvania (previously named Coventina Healthcare Enterprises), which develops and markets medical device products, where he was previously Chief Operating Officer. From 2000 until 2007, Mr. Swoveland served as Chief Financial Officer of Body Media, Inc., a life-science company specializing in the design and development of wearable body monitoring products and services. Prior thereto, Mr. Swoveland held various positions, including Vice-President of Finance, Treasurer and interim Chief Financial Officer with Equitable Resources, Inc., a diversified natural gas company, from 1994 to September 2000. Mr. Swoveland serves as a member of the Board of Directors of Linn Energy, LLC, a public, independent natural gas and oil company. Mr. Swoveland serves as Presiding Independent Director, and serves on the Audit Committee, the Planning and Finance Committee and Executive Committee.
 
 James M. Trimble has served as Managing Director of Grand Gulf Energy, Limited (ASX:GGE), a public company traded on the Australian Exchange, since August 2006. In January 2005, Mr. Trimble founded and has since served as President and Chief Executive Officer of the U.S. subsidiary Grand Gulf Energy Company LLC, an exploration and development company focused primarily on drilling in mature basins in Texas, Louisiana and Oklahoma. From 2000 through 2004, Mr. Trimble was Chief Executive Officer of Elysium Energy and then Tex-Cal Energy LLC, both were privately held oil and gas companies that he was brought in to take through troubled workout solutions. Prior to this, he was Senior Vice President of Exploration and Production for Cabot Oil and Gas (NYSE:COG). From November 2002 until May 2006, he also served as a Director of Blue Dolphin Energy, an independent oil and gas company with operations in the Gulf of Mexico. Mr. Trimble serves on the Planning and Finance Committee and the Compensation Committee.
 
 Kimberly Luff Wakim, an attorney and a Certified Public Accountant, is a Partner with the Pittsburgh, Pennsylvania law firm Thorp, Reed & Armstrong LLP, where she serves as a member of the Executive Committee and is the Practice Group Leader for the Bankruptcy and Financial Restructuring Practice Group. Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990. Ms. Wakim was previously an auditor with Main Hurdman (now KPMG) and was Assistant Controller for PDC from 1982 to 1985. She has been a member of AICPA and the West Virginia Society of CPAs for more than fifteen years. Ms. Wakim serves as Chairman of the Compensation Committee and serves on the Audit Committee and the Nominating and Governance Committee.


Audit Committee


The Audit Committee is composed entirely of persons whom the Board has determined to be independent under NASDAQ Listing Rule 5605(a)(2), Section 301 of the Sarbanes-Oxley Act of 2002 and Section 10A(m)(3) of the Exchange Act. Anthony J. Crisafio chairs the Audit Committee; other members are Directors Wakim, Casabona and Swoveland. The Board has determined that all four members of the Audit Committee qualify as financial experts as defined by SEC regulations and that all of the Audit Committee members are independent of management.








ITEM 11.
EXECUTIVE COMPENSATION





The Partnership does not have any employees or executives of its own.  None of PDC's officers or directors receive any direct remuneration, compensation or reimbursement from the Partnership.  These persons receive compensation solely from PDC.  The Managing General Partner does not believe that PDC’s executive and non-executive compensation structure, available to officers or directors who act on behalf of the Partnership, is reasonably likely to have a materially adverse effect on the Partnership’s operations or conduct of PDC when carrying out duties and responsibilities to the Partnership, as Managing General Partner under the Agreement, or as operator under the D&O Agreement.  The management fee and other amounts paid to the Managing General Partner by the Partnership are not used to directly compensate or reimburse PDC’s officers or directors.   No management fee was paid to PDC in 2010 or 2009 as the Partnership is not required to pay a management fee other than a one-time fee paid in the initial year of formation per the Agreement.  The Partnership pays a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $100 per well per month for Partnership related general and administrative expenses that include accounting, engineering and management of the Partnership by the Managing General Partner.  See Item 13, Certain Relationships and Related Transactions, and Director Independence for a discussion of compensation paid by the Partnership to the Managing General Partner.





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Compensation Committee Interlocks and Insider Participation





There are no Compensation Committee interlocks.






ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS





The following table presents information as of December 31, 2010 concerning the Managing General Partner’s interest in the Partnership and other persons known by the Partnership to own beneficially more than 5% of the interests in the Partnership.  Each partner exercises sole voting and investing power with respect to the interest beneficially owned.





Limited Partnership UnitsPerson or Group

Number of

Units

Outstanding Which

Represent 63% of TotalPartnership Interests (1)


Number of Units Beneficially Owned


Percentage of Total Units Outstanding


Percentage of

Total Partnership

Interests

BeneficiallyOwned4,470.00Petroleum Development Corporation (2) (3) (4) (5)


-



-



0.00
%


0.00
%Investor Partners beneficially owning 5% or more, of limited partner interests


-



-



-



-





(1)
Additional general partner units were converted to limited partner interests at the completion of drilling activities.


(2)
Petroleum Development Corporation (dba PDC Energy), 1775 Sherman Street Suite 3000, Denver, Colorado 80203.


(3)
No director or officer of PDC owns interest in PDC limited partnerships.  Pursuant to the Partnership Agreement individual investor partners may present their units to PDC for purchase subject to certain conditions; however, PDC is not obligated to purchase more than 10% of the total outstanding units during any calendar year.


(4)
The Percentage of “Total Partnership Interests Beneficially Owned” by PDC with respect to its limited partnership units repurchased, is determined by multiplying the percentage of limited partnership units repurchased by PDC to total limited partnership units, by the limited partners’ percentage ownership in the Partnership.  As of December 31, 2010, PDC has repurchased no units of Partnership interest from Investor Partners.


(5)
In addition to this ownership percentage of limited partnership interest, Petroleum Development Corporation (dba PDC Energy) owns a Managing General Partner interest of 37%.








ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE





Compensation to the Managing General Partner and Affiliates





The Managing General Partner transacts all of the Partnership’s business on behalf of the Partnership.Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation.  The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the Drilling and Operating Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations.  This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS.  These rates are reflective of similar costs incurred by comparable operators in the production field.  PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services or other services for the Partnership at the lesser of cost or competitive prices in the area of operations.





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Industry specialists, employed by PDC to support the Partnership’s business operations include the following:





·
Geoscientists who identify and develop PDC’s drilling prospects and oversee the drilling process;


·
Petroleum engineers who plan and direct PDC’s well completions and recompletions, construct and operate PDC’s well and gathering lines, and manage PDC’s production operations;


·
Petroleum reserve engineers who evaluate well reserves at least annually and monitor individual well performance against expectations; and


·
Full-time well tenders and supervisors who operate PDC wells.





Salary and employment benefit costs for the above specialized services are covered by the monthly fees paid to the Managing General Partner as more fully described in the preceding Item 11, Executive Compensation.





PDC procures services on behalf of the Partnership for costs and expenses related to the purchase or repairs of equipment, materials, third-party services, brine disposal and the rebuilding of access roads.  These are charged at the invoice cost of the materials purchased or the third-party services performed.  In addition to the industry specialists above who provide technical management, PDC may provide services, at competitive rates, from PDC-owned service rigs, a water truck, steel tanks used temporarily on the well location during the drilling and completion of a well, roustabouts and other assorted small equipment and services.  A roustabout is a natural gas and oil field employee who provides skilled general labor for assembling well components and other similar tasks.  PDC may lay short gathering lines, or may subcontract all or part of the work where it is more cost effective for the Partnership.





See Note 9, Transactions with Managing General Partner and Affiliates to the accompanying financial statements, for information regarding compensation to and transactions with the Managing General Partner and affiliates.





Related Party Transaction Policies and Approval





The Agreement and the D&O Agreement with Petroleum Development Corporation (dba PDC Energy) govern related party transactions, including those described above.  The Partnership does not have any written policies or procedures for the review, approval or ratification of transactions with related persons outside of the referenced agreements.





Director Independence





The Partnership has no directors.  The Partnership is managed by the Managing General Partner.  See Item 10, Directors, Executive Officers and Corporate Governance.








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ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES





The following table presents amounts charged by the Partnership’s independent registered public accounting firm, PricewaterhouseCoopers LLP (“PwC”) for the years described:





Year Ended December 31,Type of Service

2010


2009Audit Fees (1)

$
140,000


$
185,000Tax Fees (2)


-



7,000Total fees

$
140,000


$
192,000




(1)
Audit fees consist of professional service fees billed for the audit of the Partnership’s annual financial statements which accompany the Partnership’s Annual Report on Form 10-K, including reviews of the Partnership’s quarterly condensed interim financial statements which accompany this report.


(2)
Tax fees consist primarily of professional services fees for tax compliance for assistance with preparation of the Partnership’s annual IRS Form 1065 and individual partners’ Schedule K-1.





Audit Committee Pre-Approval Policies and Procedures





The Sarbanes-Oxley Act of 2002 requires that all services provided to the Partnership by its independent registered public accounting firm be subject to pre-approval by the Audit Committee or authorized members of the Committee.  The Partnership has no Audit Committee.  The Audit Committee of PDC, as Managing General Partner, has adopted policies and procedures for pre-approval of all audit services and non-audit services to be provided by the Partnership's independent registered public accounting firm.  Services necessary to conduct the annual audit must be pre-approved by the Audit Committee annually at a meeting. Permissible non-audit services to be performed by the independent registered public accounting firm may also be approved on an annual basis by the Audit Committee if they are of a recurring nature.  Permissible non-audit services to be conducted by the independent registered public accounting firm, which are not eligible for annual pre-approval, must be pre-approved individually by the full Audit Committee or by an authorized Audit Committee member.  Actual fees incurred for all services performed by the independent registered public accounting firm will be reported to the Audit Committee after the services are fully performed.  The duties of the Committee are described in the Audit Committee Charter, which is available at the Managing General Partner, PDC’s, website under Corporate Governance.








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 Table of Contents





PART IV





ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES





(a)           The index to Financial Statements is located on page F-1.


(b)           Exhibits index.





Incorporated by ReferenceExhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith3.1

Limited Partnership Agreement

10-12G/A Amend 1

000-53201

3

08/06/20083.2

Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law

10-12G/A Amend 1

000-53201

3.1

08/06/200810.1

Form of assignment of leases to the Partnership

10-12G/A Amend 1

000-53201

10.1

08/06/200810.2

Drilling and operating agreement between PDC as Managing General Partner, and the Partnership

10-12G/A Amend 1

000-53201

10.2

08/06/200810.3

Audited Consolidated Financial Statements for the year ended December 31, 2010 of Petroleum Development Corporation (dba PDC Energy) and its subsidiaries, as Managing General Partner of the Partnership

10-K

000-07246



02/24/201110.4

Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999

10-12G/A Amend 3

000-53201

10.3

03/31/200910.5

Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982-A Limited and Cattle Creek Company, dated October 14, 1983

10-12G/A Amend 3

000-53201

10.4

03/31/200910.6

Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and SHF Partnership, a Colorado general partnership, Trailblazer Oil and Gas, Inc., Alfa Resources, Inc., Pulsar Oil and Gas, Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert Lanari, an individual, and Toby A Martinez, an individual, dated September 21, 1983

10-12G/A Amend 3

000-53201

10.5

03/31/2009




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Incorporated by ReferenceExhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith10.7

Domestic Crude Oil Purchase Agreement with ConocoPhillips Company, dated January 1, 1993, as amended by agreements with Teppco Crude Oil, LLC dated August 2, 2007; September 24, 2007; October 17, 2007; January 7, 2008; January 15, 2008; and April 17, 2008

10-12G/A Amend 3

000-53201

10.6

03/31/200910.8

Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and Petroleum Development Corporation, dated as of June 1, 2006

10-12G/A Amend 3

000-53201

10.7

03/31/200910.9

Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and Petroleum Development Corporation, dated April 22, 2008

10-Q

000-53201

10.1

05/18/200931.1

Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership.









X31.2

Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership.









X32.1

Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership.









X99.2

Report of Independent Petroleum Consultants−Ryder Scott Company, LP









X





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 Table of Contents




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/ Richard W. McCullough


Richard W. McCullough


Chairman and Chief Executive Officer


of Petroleum Development Corporation (dba PDC Energy)


March 30, 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/ Richard W. McCullough

Chairman and Chief Executive Officer
March 30, 2011Richard W. McCullough

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant(Principal executive officer)/s/ Gysle R. Shellum

Chief Financial Officer
March 30, 2011Gysle R. Shellum

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant(Principal financial officer)/s/ R. Scott Meyers

Chief Accounting Officer
March 30, 2011R. Scott Meyers

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant(Principal accounting officer)/s/ Joseph E. Casabona

Director
March 30, 2011Joseph E. Casabona

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant/s/ Anthony J. Crisafio

Director
March 30, 2011Anthony J. Crisafio

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant/s/ Jeffrey C. Swoveland

Director
March 30, 2011Jeffrey C. Swoveland

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant/s/ Kimberly Luff Wakim

Director
March 30, 2011Kimberly Luff Wakim

Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant




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ROCKIES REGION 2007 LIMITED PARTNERSHIP





Index to Financial Statements








Report of Independent Registered Public Accounting Firm
F-2Balance Sheets - December 31, 2010 and 2009
F-3Statements of Operations - For the Years Ended December 31, 2010 and 2009
F-4Statements of Partners' Equity - For the Years Ended December 31, 2010 and 2009
F-5Statements of Cash Flows - For the Years Ended December 31, 2010 and 2009
F-6Notes to Financial Statements
F-7Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited
F-22




F - 1
 Table of Contents




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM






To the Partners of the Rockies Region 2007 Limited Partnership,





In our opinion, the accompanying balance sheets and the related statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of Rockies Region 2007 Limited Partnership (the "Partnership") at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Partnership's management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.





As discussed in Note 9 to the financial statements, the Partnership has significant related party transactions with Petroleum Development Corporation and its subsidiaries.






/s/ PricewaterhouseCoopers LLP


Pittsburgh, Pennsylvania


March 30, 2011





F - 2
 Table of Contents





ROCKIES REGION 2007 LIMITED PARTNERSHIP








Balance Sheets


As of December 31, 2010 and 2009





Assets

2010


2009Current assets:Cash and cash equivalents

$
690,377


$
4,229Accounts receivable


1,175,972



1,542,805Crude oil inventory


59,031



34,954Due from Managing General Partner-derivatives


3,178,313



2,601,225Due from Managing General Partner-other, net


534,115



2,664,966Total current assets


5,637,808



6,848,179Natural gas and crude oil properties, successful efforts method, at cost


79,934,322



118,891,102Less:  Accumulated depreciation, depletion and amortization


(29,699,641
)


(31,583,376
)Natural gas and crude oil properties, net


50,234,681



87,307,726Due from Managing General Partner-derivatives


4,689,041



1,797,313Total noncurrent assets


54,923,722



89,105,039Total Assets

$
60,561,530


$
95,953,218Liabilities and Partners' EquityCurrent liabilities:Accounts payable and accrued expenses

$
136,704


$
193,789Due to Managing General Partner-derivatives


2,580,843



2,081,345Total current liabilities


2,717,547



2,275,134Due to Managing General Partner-derivatives


3,556,891



5,268,688Asset retirement obligations


727,952



680,648Total liabilities


7,002,390



8,224,470Commitments and contingent liabilitiesPartners' equity:Managing General Partner


14,622,934



27,265,689Limited Partners -  4,470 units issued and outstanding


38,936,206



60,463,059Total Partners' equity


53,559,140



87,728,748Total Liabilities and Partners' Equity

$
60,561,530


$
95,953,218





See accompanying notes to financial statements.





F - 3
 Table of Contents





ROCKIES REGION 2007 LIMITED PARTNERSHIP








Statements of Operations


For the Years Ended December 31, 2010 and 2009





2010


2009Revenues:Natural gas, NGLs and crude oil sales

$
14,489,015


$
18,260,936Commodity price risk management gain (loss), net


8,150,531



(5,113,706
)Total revenues


22,639,546



13,147,230Operating costs and expenses:Natural gas, NGLs and crude oil production cost


5,061,490



4,633,787Direct costs - general and administrative


200,907



496,788Depreciation, depletion and amortization


9,456,143



15,554,781Loss on impairment of natural gas and crude oil  properties


27,687,418



-Accretion of asset retirement obligations


47,304



16,144Total operating costs and expenses


42,453,262



20,701,500Loss from operations


(19,813,716
)


(7,554,270
)Interest expense


-



(3,779
)Interest income


-



19,295Net loss

$
(19,813,716
)

$
(7,538,754
)Net loss allocated to partners

$
(19,813,716
)

$
(7,538,754
)Less:  Managing General Partner interest in net loss


(7,331,075
)


(2,789,339
)Net loss allocated to Investor Partners

$
(12,482,641
)

$
(4,749,415
)Net loss per Investor Partner unit

$
(2,793
)

$
(1,063
)Investor Partner units outstanding


4,470.00



4,470.00





See accompanying notes to financial statements.





F - 4
 Table of Contents





ROCKIES REGION 2007 LIMITED PARTNERSHIP








Statements of Partners' Equity


For the Years Ended December 31, 2010 and 2009





Investor

Partners


Managing

General

Partner


TotalBalance, December 31, 2008

$
86,568,136


$
42,962,019


$
129,530,155Distributions to partners


(21,355,662
)


(12,906,991
)


(34,262,653
)Net loss


(4,749,415
)


(2,789,339
)


(7,538,754
)Balance, December 31, 2009


60,463,059



27,265,689



87,728,748Distributions to partners


(9,044,212
)


(5,311,680
)


(14,355,892
)Net loss


(12,482,641
)


(7,331,075
)


(19,813,716
)Balance, December 31, 2010

$
38,936,206


$
14,622,934


$
53,559,140





See accompanying notes to financial statements.





F - 5
 Table of Contents




ROCKIES REGION 2007 LIMITED PARTNERSHIP





Statements of Cash Flows


For the Years Ended December 31, 2010 and 2009





2010


2009Cash flows from operating activities:Net loss

$
(19,813,716
)

$
(7,538,754
)Adjustments to net loss to reconcile to net cash provided by operating activities:Depreciation, depletion and amortization


9,456,143



15,554,781Accretion of asset retirement obligations


47,304



16,144Unrealized (gain) loss on derivative transactions


(4,681,115
)


18,584,227Loss on impairment of natural gas and crude oil properties


27,687,418



-Changes in operating assets and liabilities:Decrease in accounts receivable


366,833



1,258,644(Increase) decrease in crude oil inventory


(24,077
)


9,608Decrease in accounts payable and accrued expenses


(57,085
)


(557,115
)Decrease in due from Managing General Partner, Net


2,130,851



6,184,203Net cash provided by operating activities


15,112,556



33,511,738Cash flows from investing activities:Capital expenditures for natural gas and crude oil properties


(70,516
)


(597,849
)Net cash used in investing activities


(70,516
)


(597,849
)Cash flows from financing activities:Distributions to Partners


(14,355,892
)


(34,262,653
)Net cash used in financing activities


(14,355,892
)


(34,262,653
)Net increase (decrease) in cash and cash equivalents


686,148



(1,348,764
)Cash and cash equivalents, beginning of year


4,229



1,352,993Cash and cash equivalents, end of year

$
690,377


$
4,229Supplemental cash flow information:Cash payments for:Interest

$
-


$
3,779Supplemental disclosure of non-cash activity:Asset retirement obligation, with corresponding increase tonatural gas and crude oil properties

$
-


$
248,394





See accompanying notes to financial statements.





F - 6
 Table of Contents





ROCKIES REGION 2007 LIMITED PARTNERSHIP





Notes to Financial Statements





NOTE 1 - GENERAL





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 December 31, 2010, there were 1,791 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 Limited Partnership 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.  Through December 31, 2010, the Managing General Partner has repurchased no units of Partnership interests from Investor Partners and owns 37% of the Partnership.





The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner’s limited partner unit repurchase program, see Note 8, Partners’ Equity and Cash Distributions.





NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES





Management’s Estimates





The preparation of the Partnership’s financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S.”) requires the Partnership to make estimates and assumptions that affect the amounts reported in the Partnership’s financial statements and accompanying notes. Actual results could differ from those estimates.  Estimates which are particularly significant to the financial statements include estimates of natural gas, natural gas liquids (“NGL”) and crude oil sales revenue, natural gas, NGLs and crude oil reserves, future cash flows from natural gas and crude oil properties and valuation of derivative instruments.





Basis of Presentation





The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of the Partnership.





Cash and Cash Equivalents.The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents.  The Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution.  The balance in the Partnership’s account is insured by Federal Deposit Insurance Corporation, or FDIC, up to $250,000 through December 31, 2013.  The Partnership has not experienced losses in any such accounts to date and limits the Partnership’s exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.





Accounts Receivable and Allowance for Doubtful Accounts.The Partnership’s accounts receivable are from purchasers of natural gas, NGLs and crude oil production.  The Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by the Partnership’s Managing General Partner.  The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers.  No allowance was deemed necessary at December 31, 2010 or 2009.





F - 7
 Table of Contents





ROCKIES REGION 2007 LIMITED PARTNERSHIP





Notes to Financial Statements






Commitments.As Managing General Partner, PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of the Partnership’s wells as required by governmental agencies.  If a government agency were required to access these performance bonds to cover plugging, reclaiming or abandonment costs on a Partnership well, the Partnership would be obligated to fund any amounts in excess of funds previously withheld by the Managing General Partner to cover these expenses.





Inventory.  Inventory consists of crude oil, stated at the lower of cost to produce or market.





Derivative Financial Instruments.The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and crude oil.  The Managing General Partner employs established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments.  The Managing General Partner’s policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.





All derivative assets and liabilities are recorded on the balance sheets at fair value.  PDC, as Managing General Partner, has elected not to designate any of the Partnership’s derivative instruments as hedges.  Accordingly, changes in the fair value of the Partnership’s derivative instruments are recorded in the Partnership’s statements of operations and the Partnership’s net income is subject to greater volatility than if the Partnership’s derivative instruments qualified for hedge accounting. Changes in the fair value of derivative instruments related to the Partnership’s natural gas and crude oil sales are recorded in the line captioned, “Commodity price risk management gain (loss), net.”  As positions designated to the Partnership settle, the realized gains and losses are netted for distribution.  Net realized gains are paid to the Partnership and net realized losses are deducted from the Partnership’s cash distributions generated from production.  The Partnership bears its designated share of counterparty risk.





Validation of a contract’s fair value is performed internally.  While the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in the Partnership’s pricing methodologies or the underlying assumptions could result in significantly different fair values.  See Note 3, Fair Value of Financial Instruments and Note 4, Derivative Financial Instruments, for a discussion of the Partnership’s derivative fair value measurements and a summary fair value table of open positions as of December 31, 2010 and 2009.





Natural Gas and Crude Oil Properties.Significant accounting polices related to the Partnership’s properties and equipment are discussed below.





The Partnership accounts for its natural gas and crude oil properties (the “Properties”) under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves.  Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves.  The Partnership calculates quarterly depreciation, depletion and amortization ("DD&A") expense by using as the denominator the Partnership’s estimated quarter-end reserves adjusted to add back current period production.  Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss.  Upon the sale of individual wells, the proceeds are credited to accumulated DD&A.See Supplemental Natural Gas, NGL and Crude Oil Information – Unaudited, Net Proved Reserves for additional information regarding the Partnership’s reserve reporting.  In accordance with the Agreement, all capital contributed to the Partnership after deducting syndication costs and a one-time management fee was used solely for the drilling of natural gas and crude oil wells.  Accordingly, all such funds were advanced to the Managing General Partnership as of the last day of the year in which the Partnership was formed.  The Partnership does not maintain an inventory of undrilled leases.





F - 8
 Table of Contents




ROCKIES REGION 2007 LIMITED PARTNERSHIP





Notes to Financial Statements








Proved Reserves.  Partnership estimates of proved reserves are based on those quantities of natural gas, NGLs and crude oil which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations.  Annually, the Managing General Partner engages independent petroleum engineers to prepare a reserve and economic evaluation of the Partnership’s properties on a well-by-well basis as of December 31.  Additionally, the Partnership adjusts reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas, NGLs and crude oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Partnership’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s depreciation, depletion and amortization (“DD&A”) expense, a change in the Partnership’s estimated reserves could have an effect on the Partnership’s net income.





Proved Property Impairment.  The Partnership assesses its producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold.  The estimates of future prices may differ from current market prices of natural gas, NGLs and crude oil.  Certain events, including but not limited to, downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership’s proved natural gas and crude oil properties.  If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value.  Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date.  Estimated discounted future net cash flows are determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and oil reserves. Due to the availability of new reserve information, the Partnership reviewed its proved natural gas and crude oil properties for impairment at December 31, 2010 and 2009.  See Note 10, Impairment of Capitalized Costs for additional disclosure related to the Partnership’s proved property impairment.





Production Tax Liability.Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which the Partnership produces natural gas, NGLs and crude oil. The Partnership’s share of these taxes is expensed to the account “Natural gas, NGLs and crude oil production costs.”  The Partnership’s production taxes payable are included in the caption “Accounts payable and accrued expenses” on the Partnership’s balance sheets.





Income Taxes.Since the taxable income or loss of the Partnership is reported in the separate tax returns of the individual investor partners, no provision has been made for income taxes by the Partnership.





Asset Retirement Obligations.The Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spudded.  Upon initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability.  Over time, the liabilities are accreted for the change in present value.  The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense.  If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.  Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling retirement obligations.  See Note 6, Asset Retirement Obligations for a reconciliation of the changes in the Partnership’s asset retirement obligation from January 1, 2009, to December 31, 2010.





F - 9
 Table of Contents





ROCKIES REGION 2007 LIMITED PARTNERSHIP





Notes to Financial Statements





Revenue Recognition.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.  The Partnership currently uses the “net-back” method of accounting for transportation arrangements of the Partnership’s natural gas sales.  The Managing General Partner sells the Partnership’s natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Partnership’s customers and reflected in the wellhead price.  The majority of the Partnership’s natural gas, NGLs and crude oil is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well.  Virtually all of the Managing General Partner’s contract pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions.





Recent Accounting Standards.





The following standards have been recently adopted:





Fair Value Measurements and Disclosures.In January 2010, the Financial Accounting Standards Board (“FASB”) issued changes clarifying existing disclosure requirements related to fair value measurements.  The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers.  The adoption of these changes as of January 1, 2010, did not have a material impact on the Partnership’s accompanying financial statements.





The following standards have been recently issued:





Fair Value Measurements and Disclosures.In January 2010, the FASB issued changes clarifying existing disclosure requirements and requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements.  The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers.  These changes will be effective for the Partnership’s financial statements issued for the first interim or annual reporting period beginning after December 15, 2009, except for gross presentation of the Level 3 roll forward, which will become effective for annual reporting periods beginning after December 15, 2010.  The Partnership’s adoption did not have a material effect on the Partnership’s financial statements and related disclosures.





Internal Control over Financial Reporting in Exchange Act Periodic Reports.By Final Rule effective September 21, 2010, the SEC amended its rules and forms to conform them to Section 404(c) of the Sarbanes-Oxley Act of 2002, or SOX, as added by the Dodd-Frank Wall Street Reform and Consumer Protection Act.  The new SEC rules permanently exempt the Partnership, as a smaller reporting company filer, from the SOX requirement that registrants obtain and include in their annual report, filed with the SEC, their independent registered public accounting firm’s attestation report on the effectiveness of the registrant’s internal controls over financial reporting.





Subsequent Events.The Managing General Partner has evaluated the Partnership’s activities subsequent to December 31, 2010 through the issuance of the financial statements, and has concluded that no material subsequent events have occurred that would require additional recognition in the Partnership’s financial statements or disclosure in the notes to the Partnership’s financial statements.





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Notes to Financial Statements






NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS





Derivative Financial Instruments





Determination of Fair Value. The Partnership’s fair value measurements are estimated pursuant to a fair value hierarchy that requires the Partnership to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels.  The three levels of inputs that may be used to measure fair value are defined as:





·
Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.  Included in Level 1 are the Partnership’s commodity derivative instruments for New York Mercantile Exchange, or NYMEX, based natural gas swaps.





·
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.  Included in Level 3 are the Partnership’s commodity derivative instruments for Colorado Interstate Gas, or CIG, based natural gas swaps, crude oil swaps, natural gas and crude oil collars and the Partnership’s natural gas basis protection derivative instruments.





Derivative Financial Instruments.  The Partnership measures the fair value of its derivative instruments based upon quoted market prices, where available.  The valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) 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.  The methods described above may produce a fair value calculation that may not be indicative of future fair values.  The Managing General’s valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument 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 the Managing General Partner’s derivative contracts.  The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  Based on the Managing General Partner’s 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 is insignificant.  Validation of Partnership’s contracts’ fair value is performed internally and while the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair values.  While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.  For more information concerning the Partnership’s concentration of credit risk and the Managing General Partner’s evaluation of that risk, see Note 5, Concentration of Risk, below.





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Notes to Financial Statements





The following table presents, for each hierarchy level, the Partnership’s assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of December 31, 2010 and 2009.





Level 1


Level 3


TotalAs of December 31, 2009Assets:Commodity based derivatives

$
1,818,987


$
2,579,551


$
4,398,538Total assets


1,818,987



2,579,551



4,398,538Liabilities:Commodity based derivatives


(157,926
)


(425,911
)


(583,837
)Basis protection derivative contracts


-



(6,766,196
)


(6,766,196
)Total liabilities


(157,926
)


(7,192,107
)


(7,350,033
)Net asset (liability)

$
1,661,061


$
(4,612,556
)

$
(2,951,495
)As of December 31, 2010Assets:Commodity based derivatives

$
7,511,512


$
355,842


$
7,867,354Total assets


7,511,512



355,842



7,867,354Liabilities:Commodity based derivatives


-



(618,004
)


(618,004
)Basis protection derivative contracts


-



(5,519,730
)


(5,519,730
)Total liabilities


-



(6,137,734
)


(6,137,734
)Net asset (liability)

$
7,511,512


$
(5,781,892
)

$
1,729,620








The following table presents a reconciliation of the Partnership’s Level 3 fair value measurements.





December 31,2010


2009Fair value, net (liability) asset beginning of year

$
(4,612,556
)

$
15,632,732Changes in fair value included in statement of operations line item:Commodity price risk management gain (loss), net


300,016



(6,774,767
)Settlements


(1,469,352
)


(13,470,521
)Fair value, net liability end of year

$
(5,781,892
)

$
(4,612,556
)Change in unrealized gain (loss) relating to assets (liabilities) stillheld as of December 31, 2010 and 2009, respectively,included in statement of operations line item:Commodity price risk management loss, net

$
(544,556
)

$
(7,754,468
)





See Note 4, 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.





See Note 2– Summary of Significant Accounting Policies−Property and Equipment, Natural Gas and Crude Oil Properties and −Asset Retirement Obligations for a discussion of how the Partnership determined fair value for these obligations.





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Notes to Financial Statements






NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS





The Partnership’s results of operations and operating cash flows are affected by changes in market prices for natural gas and crude oil.  To mitigate a portion of the Partnership’s exposure to adverse market changes, the Managing General Partner utilizes an economic hedging strategy for the Partnership’s natural gas and crude oil sales, in which PDC, as Managing General Partner, enters into derivative contracts on behalf of the Partnership to protect against price declines in future periods.  While the Managing General Partner structures these derivatives to reduce the Partnership’s exposure to changes in price associated with the derivative commodity, they also limit the benefit the Partnership might otherwise have received from price increases in the physical market. The Managing General Partner believes the Partnership’s derivative instruments continue to be effective in achieving the risk management objectives for which they were intended.  As of December 31, 2010, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 4,269,301 MMbtu of natural gas and 28,043 Bbls of crude oil.  Partnership policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.





The Managing General Partner uses natural gas and crude oil commodity derivative instruments to manage price risk for PDC as well as its sponsored drilling partnerships.  The Managing General Partner sets these instruments for PDC and the various partnerships managed by PDC jointly by area of operations, whereby the allocation of derivative positions between PDC and each partnership is set at a fixed quantity.  New positions have specific designations relative to the applicable partnership.





As of December 31, 2010, the Partnership’s derivative instruments were comprised of commodity collars and swaps and basis protection swaps.





·
Collars contain a fixed floor price (put) and ceiling price (call).  If the index price falls below the fixed put strike price, PDC, as Managing General Partner receives the market price from the purchaser and receives the difference between the put strike price and index price from the counterparty.  If the index price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and index price to the counterparty.  If the index price is between the put and call strike price, no payments are due to or from the counterparty.





·
Swaps are arrangements that guarantee a fixed price.  If the index price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the index price and the fixed contract price from the counterparty.  If the index price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the index price and the fixed contract price to the counterparty.  If the index price and contract price are the same, no payment is due to or from the counterparty.





·
Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point.  For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.  If the market price and contract price are the same, no payment is due to or from the counterparty.





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Notes to Financial Statements





The following table presents the location and fair value amounts of the Partnership’s derivative instruments on the accompanying balance sheets as of December 31, 2010 and 2009.





Derivative instruments not
Balance Sheet

December 31,designated as hedge  (1):
Line Item

2010


2009Derivative Assets:CurrentCommodity contracts
Due from Managing General Partner-derivatives

$
3,178,313


$
2,601,225Non CurrentCommodity contracts
Due from Managing General Partner-derivatives


4,689,041



1,797,313Total Derivative Assets



7,867,354



4,398,538Derivative Liabilities:CurrentCommodity contracts
Due to Managing General Partner-derivatives


618,004



161,836Basis protection contracts
Due to Managing General Partner-derivatives


1,962,839



1,919,509Non CurrentCommodity contracts
Due to Managing General Partner-derivatives


-



422,001Basis protection contracts
Due to Managing General Partner-derivatives


3,556,891



4,846,687Total Derivative Liabilities



6,137,734



7,350,033Net fair value of derivative instruments - asset (liability)


$
1,729,620


$
(2,951,495
)





(1) As of December 31, 2010 and 2009, none of the Partnership’s derivative instruments were designated as hedges.





The following table presents the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations.





Year Ended December 31,2010


2009Statement of operations line item

Reclassification of Realized Gain (Loss) Included in Prior Periods Unrealized


Realized and Unrealized Gain For the Current Period


Total


Reclassification of Realized Gain (Loss) Included in Prior Periods Unrealized


Realized and Unrealized Gain (Loss) For the Current Period


TotalCommodity price risk management,  netRealized gain

$
519,880


$
2,949,536


$
3,469,416


$
12,096,419


$
1,374,102


$
13,470,521Unrealized (loss) gain


(519,880
)


5,200,995



4,681,115



(12,096,419
)


(6,487,808
)


(18,584,227
)Total commodity price risk management gain (loss), net

$
-


$
8,150,531


$
8,150,531


$
-


$
(5,113,706
)

$
(5,113,706
)





NOTE 5 - CONCENTRATION OF RISK





Accounts Receivable.The Partnership’s accounts receivable are from purchasers of natural gas, NGLs and crude oil production.  The Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by the Partnership’s Managing General Partner.  Inherent to the Partnership’s industry is the concentration of natural gas, NGL and crude oil sales to a few customers.  This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that its customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions.





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Notes to Financial Statements





As of December 31, 2010 and 2009, the Partnership did not record an allowance for doubtful accounts.  In making the estimate for receivables that are uncollectible, the Managing General Partner considers, among other things, historical write-offs and overall creditworthiness of the Partnership’s customers.  It is reasonably possible that the Managing General Partner’s estimate of uncollectible receivables will change periodically.  Historically, neither PDC nor any of the other partnerships managed by the Partnership’s Managing General Partner have experienced significant losses on accounts receivable.  The Partnership did not incur any losses on accounts receivable for the years ended December 31, 2010 and 2009.





Major Customers.  The following table presents the individual customers constituting 10% or more of total revenues.





Year Ended December 31,Major Customer

2010


2009DCP Midstream LP (“DCP”)

15%


14%Williams Production RMT (“Williams”),

45%


44%Suncor Energy (USA) Inc. (“Suncor”)

38%


40%





Derivative Counterparties.A significant portion of the Partnership’s future liquidity is concentrated in 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 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.  The Managing General Partner has determined based on this evaluation, that the impact of the nonperformance of the counterparties on the fair value of the Partnership’s derivative instruments is not significant.








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Notes to Financial Statements





NOTE 6 - ASSET RETIREMENT OBLIGATIONS





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





Year Ended December 31,2010


2009Balance at beginning of year

$
680,648


$
416,110Revisions in estimated cash flows


-



248,394Accretion expense


47,304



16,144Balance at end of year

$
727,952


$
680,648





If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.





NOTE 7 - COMMITMENTS AND CONTINGENCIES





Litigation.The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There are no assurances that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not be less than or exceed the amounts reserved.





Royalty Owner Class Action.On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”).  The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by the Managing General Partner pursuant to leases.  The Managing General Partner moved the case to Federal Court on June 28, 2007.  On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership.  Although the Partnership was not named as a party in the suit, the lawsuit states that this action relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s wells in the Wattenberg field.  For information regarding the number of Partnership wells located in this field, see Supplemental Natural Gas, NGL and Crude Oil Information – Unaudited, Costs Incurred in Natural Gas and Crude Oil Property Development Activities,which follows.The portion of the settlement relating to the Partnership’s wells for the year ended December 31, 2009 that has been expensed by the Partnership is approximately $39,000 including associated legal costs of approximately $3,000.  The portion of the settlement relating to the Partnership’s wells for all periods through December 31, 2009 that has been expensed by the Partnership is approximately $125,000 including associated legal costs of approximately $11,000.  This entire settlement of $114,663 was deposited by the Managing General Partner into an escrow account on November 3, 2008.  Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008.  The final settlement was approved by the court on April 7, 2009.  Settlement distribution checks were mailed in July 2009.  During September 2009, the Partnership’s share of settlement costs were paid by the Partnership and related required judicial action from the settlement of the suit was implemented in this distribution.





The Partnership is involved in various other legal proceedings that are considered normal to the Partnership’s business. Although the results cannot be known with certainty, the Managing General Partner believes that the ultimate results of such proceedings will not have a material effect on the Partnership’s financial position, results of operations or liquidity.





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Notes to Financial Statements





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 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 year ended December 31, 2010, the Managing General Partner identified existing ground contamination and the Partnership incurred expenses of $0.1 million for ground contamination remediation.  As of December 31, 2010, the Partnership’s remaining accrued environmental remediation liability is $5,000 and is included in line item captioned “Accounts payable and accrued expenses” on the Balance Sheet.  The Managing General Partner is not aware of any environmental claims existing as of December 31, 2010, which have not been provided for or would otherwise have a material impact on the Partnership’s 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 8 - PARTNERS’ EQUITY AND CASH DISTRIBUTIONS





Partners’ Equity





Limited Partner Units.A Limited Partner unit represents the individual interest of an individual investor partner in the Partnership.  No public market exists or will develop for the units.  While units of the Partnership are transferable, assignability of the units is limited, requiring the consent of the Managing General Partner.  Further, individual investor partners may request that the Managing General Partner repurchase units pursuant to the Unit Repurchase Program.





Allocation of Partners’ Interest.The table below presents the participation of the Investor Partners and the Managing General Partner in the revenues and costs of the Partnership.





Investor

Partners


Managing

General

PartnerPartnership Revenue:Natural gas, NGLs and crude oil sales


63
%


37
%Commodity price risk management gain (loss)


63
%


37
%Sale of productive properties


63
%


37
%Sale of equipment


63
%


37
%Interest income


63
%


37
%Partnership Operating Costs and Expenses:Natural gas, NGLs and crude oil production and well operations costs (a)


63
%


37
%Depreciation, depletion and amortization expense


63
%


37
%Accretion of asset retirement obligations


63
%


37
%Direct costs - general and administrative (b)


63
%


37
%





(a)
Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.


(b)
The Managing General Partner receives monthly reimbursement from the Partnership for direct costs – general and administrative incurred by the Managing General Partner on behalf of the Partnership.





Unit Repurchase Provisions.Investor Partners may request that the Managing General Partner repurchase units at any time beginning with the third anniversary of the first cash distribution of the Partnership.  The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production.  In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating to 10% of the initial subscriptions, if requested by an individual investor partner, subject to PDC’s financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the Partnership to be treated as a “publicly traded partnership” or result in the termination of the Partnership for federal income tax purposes.  Repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis.





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Notes to Financial Statements





Cash Distributions





The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly.  The Managing General Partner determines and distributes cash on a monthly basis, if funds are available for distribution.  The Managing General Partner makes cash distributions of 63% to the Investor Partners and 37% to the Managing General Partner.  Cash distributions began in May 2008.  The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:





Year Ended December 31,2010


2009Cash distributions

$
14,355,892


$
34,262,653





Distributions to Partners in 2009 were impacted by a non-recurring item which was the Partnership’s payment to the Managing General Partner for royalty settlement costs of approximately $0.1 million decreased distributions in 2009.  This amount has been previously accrued by the Partnership in “Due from (to) Managing General Partner – other, net.”  In 2010, distributions to Partners were reduced $120,000 for the withholding of funds for the Partnership’s future development of proved undeveloped reserves.





NOTE 9 - TRANSACTIONS WITH MANAGING GENERAL PARTNER AND AFFILIATES





The Managing General Partner transacts business on behalf of the Partnership under the authority of the Drilling and Operating 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 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 balance sheet line item – Due from Managing General Partner-other, net which remain undistributed or unsettled with the Partnership’s investors as of the dates indicated.





December 31,2010


2009Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers

$
875,468


$
1,594,275Commodity Price Risk Management, Realized Gain


478,306



1,724,989Other (1)


(819,659
)


(654,298
)Total Due from Managing General Partner - other, net

$
534,115


$
2,664,966





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





Additionally, certain amounts representing royalties on Partnership production paid in September 2009 were recorded by the Partnership as liabilities in the account “Due from Managing General Partner-other, net.”  These amounts, which totaled approximately $125,000 including legal fees of approximately $11,000, represented the Partnership’s share of the court approved royalty litigation payment and settlement, more fully described in Note 7, Commitments and Contingencies.During September 2009, all settlement costs related to this litigation were paid by the Partnership, to the Managing General Partner.





For more information concerning the September 2009 settlement of the Partnership’s production tax refund receivable and Colorado royalty litigation settlement liability during September 2009, and its related impact to the Partnership’s cash distributions for the month of September 2009, see Note 8, Partners’ Equity and Cash Distributions.





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Notes to Financial Statements





The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 4, Derivative Financial Instruments, with the Managing General Partner and its affiliates for years ended December 31, 2010 and 2009.  “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 statements of operations.





Year Ended December 31,2010


2009Well operations and maintenance (1)

$
3,936,833


$
3,168,860Gathering, compression and processing fees (2)


529,849



642,071Direct costs - general and administrative (3)


200,907



496,788Cash distributions (4) (5)


5,311,680



12,906,991





(1)  Under the D&O Agreement, the Managing General Partner, as operator of the wells, receives payments for well charges and lease operating supplies and maintenance expenses from the Partnership when the wells begin producing.





Well charges.  The Managing General Partner receives reimbursement at actual cost for all direct expenses incurred on behalf of the Partnership, monthly well operating charges for operating and maintaining the wells during producing operations, which reflects a competitive field rate, and a monthly administration charge for Partnership activities.





Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation.  The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the Drilling and Operating Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations.  This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS.  These rates are reflective of similar costs incurred by comparable operators in the production field.  PDC, in certain circumstances, has and may in the future, provided equipment or supplies, performed salt water disposal services and other services for the Partnership at the lesser of cost or competitive prices in the area of operations.





The Managing General Partner as operator bills non-routine operations and administration costs to the Partnership at its cost.  The Managing General Partner may not benefit by inter-positioning itself between the Partnership and the actual provider of operator services.  In no event is any consideration received for operator services duplicative of any consideration or reimbursement received under the Agreement.





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Notes to Financial Statements





The well operating, or well tending, charges cover all normal and regularly recurring operating expenses for the production, delivery and sale of natural gas, NGLs and crude oil, such as:





·
well tending, routine maintenance and adjustment;


·
reading meters, recording production, pumping, maintaining appropriate books and records; and


·
preparing production related reports to the Partnership and government agencies.





The well supervision fees do not include costs and expenses related to:





·
the purchase or repairs of equipment, materials or third-party services;


·
the cost of compression and third-party gathering services, or gathering costs;


·
brine disposal; and


·
rebuilding of access roads.





These costs are charged at the invoice cost of the materials purchased or the third-party services performed.





Lease Operating Supplies and Maintenance Expense.  The Managing General Partner and its affiliates may enter into other transactions with the Partnership for services, supplies and equipment during the production phase of the Partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment.  Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.





(2)  Under the Agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the natural gas produced by the Partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area from the point the natural gas from the well is commingled with natural gas from other wells.  In such a case, the Managing General Partner uses gathering systems already owned by PDC, or PDC constructs the necessary facilities if no such line exists.  In such a case, the Partnership pays a gathering, compression and processing fee directly to the Managing General Partner at competitive rates.  If a third-party gathering system is used, the Partnership pays the gathering fee charged by the third-party gathering the natural gas.





(3)  The Managing General Partner is reimbursed by the Partnership for all direct costs expended by them on the Partnership’s behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.





(4)  The Agreement provides for the allocation of cash distributions 63% to the Investors Partners and 37% to the Managing General Partner.  For additional disclosure regarding the allocation of cash distributions, refer to Note 8, Partners’ Equity and Cash Distributions.





(5)  Distributions to Partners in 2009 were impacted by non-recurring items. See Note 8, Partners’ Equity and Cash Distributions for detailed information on these transactions.





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ROCKIES REGION 2007 LIMITED PARTNERSHIP





Notes to Financial Statements





NOTE 10 – IMPAIRMENT OF CAPITALIZED COSTS





The Partnership assesses its proved natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold.  The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event.  Therefore, impairment tests are completed as of December 31 each year.  The estimates of future prices may differ from current market prices of natural gas and crude oil.  Certain events, including but not limited to, downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership’s proved natural gas and crude oil properties.  If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, as occurred for the year ended December 31, 2010, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value.  The Partnership’s estimated production used in the impairment testing is taken from the annual reserve report (See Supplemental Natural Gas, NGL and Crude Oil Information –Unaudited—Net Proved Reserves).  Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date.  Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves.  A decline in the forward price curves used to estimate future cash flows at December 31, 2010, accompanied by lower reserves reflected in the Partnership’s annual reserve report resulted in an impairment in the fourth quarter of 2010.  This downward revision to the future net cash flows resulted primarily from an 8,034 or 33.5% decrease in future estimated MMcfs of natural gas production due to well economics and a reduction in prices from 2009.  The Partnership recorded an impairment loss, the first natural gas and crude oil properties impairment recognized by the Partnership since it began operations in 2007, of $27.7 million for the year ended December 31, 2010.  The impairment loss resulted from the downward revision to the fair value of discounted future net cash flows of production activities in the Grand Valley Field in Colorado.





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ROCKIES REGION 2007 LIMITED PARTNERSHIP





Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited





Net Proved Reserves





The Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. (Ryder Scott), to estimate the Partnership’s 2010 and 2009 natural gas, NGLs and crude oil reserves.  These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.





Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change.  The Partnership’s net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate.  Proved developed reserves are the quantities of natural gas, NGL and crude oil expected to be recovered from currently producing zones under the continuation of present operating methods.  Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development.





The Partnership’s estimated proved undeveloped reserves consist entirely of reserves attributable to the Wattenberg Field’s future initial Codell formation recompletion of the five productive J-Sand wells and future refracturing of 72 of the Partnership’s Codell formation wells.  These additional Codell formation development activities, which are expected to start in 2012 or later as part of the Additional Codell Formation Development Plan, generally occur five to ten years after initial well drilling.  Funding for this additional development work is expected to be provided by withholding distributions from investors.  The Managing General Partner began to withhold funds from Partnership distributions in October 2010 for some of the Partnerships, in which they are the Managing General Partner.  Funds of $120,000 and $370,000 have been withheld from this Partnership’s distributions as of December 31, 2010 and February 28, 2011, respectively.  Currently, the Partnership expects these additional development activities to be completed through approximately 2015.  The time frame for development activity is impacted by individual well decline curves as well as the plan to maximize the financial impact of the additional development.





Reporting on NGLs in 2010





As a result of a computer system upgrade during the second half of 2009, the Managing General Partner was able to accumulate the Partnership’s NGLs sales revenues and production volumes for 2010.  Prior to the system upgrade, the Partnership’s NGLs sales revenues and production volumes were included in the natural gas sales revenues and production volume statistical information.  The NGLs are extracted by third-party purchasers from the Partnership’s natural gas production, after delivery.  To provide additional information to the reader, the Partnership has revised the method of completing the year end reserve reports.  The December 31, 2010 reserve report provides separately disclosed information relating to natural gas, NGLs and crude oil and condensate reserves.





The prices used to estimate the Partnership’s reserves, by commodity, are presented below.





Price Used to Estimate ReservesAs of December 31,

Crude Oil

(per Bbl)


Natural Gas

(per Mcf)(1)


NGLs

(per Bbl)(1)2010(2)

$
71.08


$
3.22


$
37.602009(2)


54.54



3.07



-




(1)
Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2010 and 2009.


(2)
For 2010 and 2009, represents a 12-month average price calculated as the unweighted arithmetic average of the price on the first day of each month January through December.




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ROCKIES REGION 2007 LIMITED PARTNERSHIP





Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited




The Partnership’s estimated 2010 and 2009 reserve volumes below were based on 12-month average prices.  The following table presents the changes in estimated quantities of the Partnership’s reserves, all of which are located within the U. S.





Natural Gas

(MMcf)


NGLs

(MBbl)


Crude Oil and Condensate

(MBbl)


Natural Gas Equivalent

(MMcfe)Proved Reserves:Proved reserves, January 1, 2009


32,771



-



1,326



40,727Revisions of previous estimates


(781
)


-



2



(769
)Production


(3,901
)


-



(144
)


(4,765
)Proved reserves, December 31, 2009


28,089



-



1,184



35,193Revisions of previous estimates and reclassifications


(5,554
)


494



22



(2,458
)Production


(2,244
)


(29
)


(81
)


(2,904
)Proved reserves, December 31, 2010


20,291



465



1,125



29,831Proved Developed Reserves, as of:December 31, 2009


24,893



-



550



28,193December 31, 2010


16,983



185



475



20,943Proved Undeveloped Reserves, as of:December 31, 2009


3,196



-



634



7,000December 31, 2010


3,308



280



650



8,888








2010 Activity.At December 31, 2010, the Partnership’s estimated proved reserves experienced a net upward revision of previous estimates of 22 MBbls of crude oil and a net downward revision of previous estimates of 5,554 MMcfs of natural gas. Additionally, the Partnership reclassified 494 MBbls of NGLs which were previously included and reported in 2009, with the Partnership’s proved natural gas reserves.  These net revisions are the result in part, of revisions to proved developed producing reserves that includes an increase of approximately 6 MBbls of crude oil and a decrease of approximately 5,666 MMcfs of natural gas accompanied by an increase of 214 MBbls of NGLs due to the reclassification, previously described.  The revisions were primarily due to a decrease in performance projections in the Grand Valley Field’s wells that was partially offset by an increase in performance projections in the Wattenberg Field’s wells. The change in field operational performance was accompanied by increased natural gas and crude oil pricing.  The revision to proved undeveloped reserves include increases of 16 MBbls of crude oil and 112 MMcfs of natural gas accompanied by an increase of 280 MBbls of NGLs due to the reclassification, previously described. The upward revision to proved undeveloped reserves was due in part, to the improved economics resulting from the increase of two well refracturing opportunities scheduled to be completed under the Additional Codell Formation Development Plan, as well as improved economics resulting from somewhat higher twelve-month average natural gas prices and substantially higher twelve-month average crude oil prices in addition to the Wattenberg Field NGLs reserve reclassification.  There were no proved undeveloped reserves developed in 2010 and 2009.





2009 Activity.At December 31, 2009, the Partnership’s estimated proved natural gas and crude oil reserves experienced an upward revision of previous estimates of 2 MBbls of crude oil and a downward revision of previous estimates of 781 MMcfs of natural gas.  This net revision is the result of revisions to proved developed producing reserves that include an increase of approximately 52 MBbls of crude oil and a decrease of 476 MMcfs of natural gas, in addition to a revision of proved undeveloped reserves amounting to decreases of approximately 50 MBbls of crude oil and 305 MMcfs of natural gas.  The net downward revision to proved developed producing natural gas and crude oil reserves was primarily due to reduced economics resulting from significantly lower twelve-month average natural gas prices that was partially offset by improved Wattenberg Field’s natural gas and crude oil operational asset performance and higher crude oil prices.  The downward revision to proved undeveloped natural gas and crude oil reserves was primarily due to reduced economics resulting from significantly lower twelve-month average natural gas prices, partially offset by higher crude oil prices.





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ROCKIES REGION 2007 LIMITED PARTNERSHIP





Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited






Capitalized Costs and Costs Incurred in Natural Gas and Crude Oil Property Development Activities





Natural gas and crude oil development costs include costs incurred to gain access to and prepare development well locations for drilling; to drill and equip developmental wells; to complete additional production formations or recomplete existing production formations and to provide facilities to extract, treat, gather and store natural gas and crude oil.





The Partnership is engaged solely in natural gas and crude oil activities, all of which are located in the continental United States.  Drilling operations began upon funding in August 2007 and all funds were advanced to the Managing General Partner as of December 31, 2007, for all planned drilling and completion activities.  The Partnership owns an undivided working interest in 99 gross (97.9 net) producing natural gas and crude oil wells which includes 75 wells located in the Wattenberg Field within the Denver-Julesburg (“DJ”) Basin, north and east of Denver, Colorado and 24 wells located in the Grand Valley Field within the Piceance Basin, situated near the western border of Colorado.  In addition to the 99 wells previously mentioned, the Partnership participated in one Grand Valley Field developmental well (1.0 net) declared to be a developmental dry hole due to downhole mechanical failure and was subsequently plugged and abandoned.





Aggregate capitalized costs related to natural gas and crude oil development and production activities with applicable accumulated DD&A are presented below:





As of December 31,2010


2009Leasehold costs

$
2,024,299


$
2,097,058Development costs


77,910,023



116,794,044Natural gas and crude oil properties, successful efforts method, at cost


79,934,322



118,891,102Less: Accumulated depreciation, depletion and amortization


(29,699,641
)


(31,583,376
)Natural gas and crude oil properties, net

$
50,234,681


$
87,307,726





Included in “Development Costs” are the estimated costs associated with the Partnership’s asset retirement obligations discussed in Note 6, Asset Retirement Obligations.





The Partnership recorded an impairment loss, the first natural gas and crude oil properties impairment recognized by the Partnership since it began operations in 2007, of $27,687,418 for the year ended December 31, 2010.  Accordingly, the Partnership reduced “Natural gas and crude oil properties” by $39,027,296 and related “Accumulated depreciation, depletion and amortization” for those properties of $11,339,878 for the years ended December 31, 2010.  See Note 10, Impairment of Capitalized Costs for additional disclosure related to the Partnership’s proved property impairment.





During 2010, the Partnership invested $0.1 million for additional equipment that supported treatment, delivery and measurement of natural gas and crude oil or environmental protection.  After the completion of the Partnership’s drilling activities, the Partnership incurred approximately $0.6 million during 2009, for natural gas and crude oil development reclamation in order to restore well pad and access road site stability and ecosystem functions.







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