UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC

______________________

FORM 10/A

(AMENDMENT NO. 2)

GENERAL FORM FOR REGISTRATION OF SECURITIES

PURSUANT TO SECTION 12(b) OR 12(g) OF

THE SECURITIES EXCHANGE ACT OF 1934

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)	(IRS Employer Identification No.)

120 Genesis Boulevard, Bridgeport, West Virginia	26330
(Address of Principal Executive Offices)	(Zip Code)

Registrant's telephone number, including area code: 304-842-3597

Securities to be registered pursuant to Section 12(b) of the Act:	Name of Each Exchange on Which
Title of Each Class to be so Registered	Each Class is to be Registered

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

Limited Partnership Interests

(Title of Class)

General Partnership Interests

(Title of Class)

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. (Check one):

Large accelerated filer   £	Accelerated filer   £
Non-accelerated filer   T	Smaller reporting company   £

Form 10/A

Rockies Regional 2007 Limited Partnership

TABLE OF CONTENTS

		Page
Item 1	Business	1
Item 1A	Risk Factors	9
Item 2	Financial Information
	(a)  Selected Financial Data	17
	(b)  Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
	(c)  Quantitative and Qualitative Disclosures About Market Risk	26
Item 3	Properties	27
Item 4	Security Ownership of Certain Beneficial Owners and Management	29
Item 5	Directors and Executive Officers and Corporate Governance	29
Item 6	Executive Compensation	32
Item 7	Certain Relationships and Related Transactions, and Director Independence	33
Item 8	Legal Proceedings	35
Item 9	Market Price of and Dividends on the Registrant’s Common Equity And Related Stockholder Matters	36
Item 10	Recent Sales of Unregistered Securities	40
Item 11	Description of Registrant’s Securities to be Registered	40
Item 12	Indemnification of Directors and Officers	44
Item 13	Financial Statements and Supplementary Data	45
Item 14	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	45
Item 15	Financial Statements and Exhibits	46
Signatures		47
Financial Statements		F-1

INFORMATION REQUIRED IN REGISTRATION STATEMENT

EXPLANATORY NOTE

The purpose of this Amendment No. 2 to Rockies Region 2007 Limited Partnership’s Form 10, filed on April 29, 2008 (the “Original Filing”) and amended on August 6, 2008, is to update the financial statements to comply with Rule 3-12 of Regulation S-X and to revise and/or add additional disclosures in response to comments received from the staff of the Securities and Exchange Commission.  This amendment includes an added disclosure of Proved Developed Reserves in Note 9, Supplement Reserve Information and Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited), to the accompanying statements.  This added disclosure did not impact our previously reported Depreciation, Depletion and Amortization in the Statement of Operations for the period from May 22, 2007 (date of inception) to December 31, 2007.  This document has been updated through September 30, 2008, the date of the filing of Form 10Q for the quarter ended June 30, 2008.  Except as described above, no other amendments are being made to the Partnership’s Form 10.

Item 1 Business

Rockies Region 2007 Limited Partnership (the "Partnership" or the "Registrant") was organized as a limited partnership on May 22, 2007 under the West Virginia Uniform Limited Partnership Act.  Upon completion of a private placement of its securities, the Partnership was funded on August 31, 2007, with initial contributions of $89,402,885 from 1,778 limited and general partners, excluding the Managing General Partner (collectively, the “Investor Partners”) and $38,659,808 from Petroleum Development Corporation (“PDC”), the Managing General Partner.  After payment of syndication costs of $9,070,450 and a one-time management fee to the Managing General Partner of $1,341,043, the Partnership had available cash of $117,651,200 to commence Partnership activities.

The Partnership owns developmental natural gas, referred to herein as gas, and oil wells located in the Wattenberg and Grand Valley fields of Colorado and will produce and sell gas and oil from these wells.  A development well is a well that is drilled close to and into the same formation as other wells which have already produced and sold gas or oil.

 The address and telephone number of the Partnership and PDC is 120 Genesis Boulevard, Bridgeport, West Virginia 26330 and (304) 842-6256.

Drilling Activities

As of September 30, 2008, the Partnership has conducted the following drilling activities by field:

	Wattenberg		Grand Valley		Total
Drilled, fractured and producing		74		24		98
Drilled to depth, not yet fractured		1		0		1
Dry hole		0		1		1
Total		75		25		100

It is anticipated that the one hundred wells identified above will be the only wells to be drilled for the Partnership.  During the remainder of 2008, the Partnership’s business plan calls for the completion of all drilling and completion activity and connection to gas pipelines for all successful wells.   Also, throughout this period the Partnership plans to produce and sell the oil and gas from the Partnership’s existing producing wells plus any new wells which are completed and connected to a pipeline, and to make distributions to the partners as outlined in the Partnership’s cash distribution policy in “Item 9, Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters.”

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Plan of Operations

The Partnership has invested in the drilling of one hundred prospects on which it has drilled an equal number of wells.  The Partnership’s working interests in these wells is generally 99.9%, but may vary for wells in which the Partnership working interest is further reduced by other outside working interests.  The Partnership operates as a single business segment.

Partnership wells in the Grand Valley field are targeted to the Mesa Verde formation. The Grand Valley Field is in the Piceance Basin, located near the western border of Colorado.  The producing interval consists of a total of 150 to 300 feet of productive sandstone divided in 10 to 15 different zones.  The production zones are separated by layers of nonproductive shale resulting in a total interval of 2,000 to 4,000 feet with alternating producing and non-producing zones.  The gas reserves and production are divided into these numerous smaller zones.

Partnership wells in the Wattenberg field are targeted to the Codell formation or deeper.  The Wattenberg Field, located north and east of Denver, Colorado, is in the Denver-Julesburg (DJ) Basin.  Wells in the area may include as many as four productive formations.  From shallowest to deepest, these are the Sussex, the Niobrara, the Codell and the J Sand.  The primary producing zone in most wells will be the Codell sand which produces a combination of gas and oil.

The typical well production profile for wells in both the Grand Valley and Wattenberg fields has an initial high production rate and relatively rapid decline, followed by years of relatively shallow decline.   Gas is the primary hydrocarbon produced; however, many wells will also produce oil.  The purchase price for the gas may include revenue from the recovery of propane and butane in the gas stream, as well as a premium for the typical high-energy content of the gas.

PDC plans to recomplete most of the wells producing from the Codell formation in the Wattenberg Field wells after they have been in production for five years or more, although the exact timing may be delayed or accelerated due to changing commodity prices.  A recompletion consists of a second fracture treatment in the same formation originally fractured in the initial completion.  PDC and other producers have found that the recompletions generally increase the production rate and recoverable reserves of the wells.  On average, the production resulting from PDC's Codell recompletions has been above the modeled economics; however, all recompletions have not and may not be successful.  The cost of recompleting a well producing from the Codell formation is about one third of the cost of a new well (currently about $195,000 for the recompletion).  PDC will charge the Partnership for the direct costs of recompletions, and will pay its proportionate share of costs based on the operating costs sharing ratios of the Partnership.  The Partnership may borrow the funds necessary to pay for the recompletions, and payment for those borrowings will be made from the Partnership production proceeds. Any such borrowings will be non-recourse to the Investor Partners in the Partnership.

Title to Properties

The Partnership holds record title in its name to the working interest in each well.  PDC provides an assignment of working interest for the well bore prior to the spudding of the well and effective the date of the spudding of the well, to the Partnership in accordance with the Drilling and Operation Agreement.  Upon completion of the drilling of all of the Partnership wells, these assignments are recorded in the applicable County.  Partnership investors rely on PDC to use its best judgment to obtain appropriate title to these working interests.  Provisions of the limited partnership agreement relieve PDC from any error in judgment with respect to the waiver of title defects.  PDC takes those steps it deems necessary to assure that title to the working interests is acceptable for purposes of the Partnership.  For additional information, see “Item 3, Properties – Title to Properties.”

Well Operations

As operator, PDC represents the Partnership in all operations matters, including the drilling, testing, completion and equipping of wells and the sale of the Partnership’s oil and gas production from wells.  PDC is the operator of all of the wells in which the Partnership owns an interest.

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PDC, in some cases, provides equipment and supplies, and performs salt water disposal services and other services for the Partnership.  PDC sells equipment to the Partnership as needed in the drilling or completion of Partnership wells.  All equipment and services are sold at the lesser of cost or competitive prices in the area of operations.

Gas Pipeline and Transmission  All of the Partnership's wells are in the vicinity of transmission pipelines and gathering systems.  PDC believes there are sufficient transmission pipelines and gathering systems for the Partnership's gas production, subject to some seasonal curtailment. This seasonal curtailment typically occurs during July and August as a result of high temperatures which reduce compressor capacity.  The reduction in production would typically amount to less than five percent of normal monthly production without an effect on pricing. The cost, timing and availability of gathering pipeline connections and service varies from area to area, well to well, and over time.  In selecting prospects for the Partnership, PDC included in its evaluation the anticipated cost, timing and expected reliability of gathering connections and capacity. When a significant amount of development work is being done in an area, production can temporarily exceed the available markets and pipeline capacity to move gas to more distant markets.  This can lead to lower gas prices relative to other areas as the producers compete for the available markets by reducing prices.  It can also lead to curtailments of production and periods when wells are shut-in due to lack of market.

Sale of Production  The Partnership sells the oil and gas produced from its wells on a competitive basis at the best available terms and prices.  PDC does not make any commitment of future production that does not primarily benefit the Partnership.  Generally, purchase contracts for the sale of oil are cancelable on 30 days notice, whereas purchase contracts for the sale of gas may range from spot market sales of short duration to contracts with a term of a number of years and that may require the dedication of the gas from a well for a period ranging up to the life of the well.

The Partnership sells gas produced at negotiated prices based upon a number of factors, including the quality of the gas, well pressure, estimated reserves, prevailing supply conditions and any applicable price regulations promulgated by the Federal Energy Regulatory Commission (“FERC”).  The Partnership sells oil produced by it to local oil purchasers at spot prices. The produced oil is stored in tanks at or near the location of the Partnership’s wells for routine pickup by oil transport trucks.

Price Hedging  Price volatility is a very significant and destabilizing factor in the oil and natural gas production industry.  The Partnership utilizes commodity based derivative instruments to manage a portion of the exposure to price volatility stemming from its oil and gas sales.  These instruments consist of Colorado Interstate Gas Index (“CIG”)-based contracts for Colorado gas production and NYMEX-traded oil futures and option contracts for oil production.  The contracts economically provide price protection for committed and anticipated oil and gas sales, generally forecasted to occur within the next one- to two-year period.  Our policies prohibit the use of oil and gas futures, swaps or options for speculative purposes and permit utilization of derivatives only if there is an underlying physical position.

The Partnership uses financial derivatives to establish "floors," "ceilings," "collars" or fixed price swaps on the possible range of the prices expected to be realized for the sale of gas and oil.  These are carried on the balance sheet at fair value with changes in fair values recognized currently in the statement of operations under the caption "Oil and gas price risk management."

The Partnership is subject to price fluctuations for gas sold in the spot market and under market index contracts.  We continue to evaluate the potential for reducing these risks by entering into derivative transactions.  In addition, we 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.  We manage price risk on only a percentage of our anticipated production, so the remaining percentage of our production is subject to the full fluctuation of market pricing.

PDC as Managing General Partner of the Partnership enters into derivative transactions including collars and fixed price swaps.  PDC enters into transactions on behalf of the Partnership in the same manner in which it enters into transactions for itself.  The Partnership participates in all hedging transactions entered into by the Managing General Partner in a given area after the partnership is formed. The transactions are on a production month basis; therefore the Partnership may participate in a hedge for a future period before it has current production from that area.  As the Partnership continues to drill and put wells into production, its share of the derivative positions will increase in future periods.  We believe that in this rapidly changing price environment, derivative positions are desirable to obtain more predictable results and to protect against possible severe price declines during this crucial stage of flush production from the Partnership wells.  This allocation methodology is considered reasonable by management and provides this result to the Partnership.

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Drilling and Operating Agreement The Partnership has entered into a drilling and operating agreement (Agreement) with PDC.  The drilling and operating agreement provides that the operator conducts and directs drilling operations and has full control of all operations on the Partnership's wells.  The operator has no liability to the Partnership for losses sustained or liabilities incurred, except as may result from the operator's negligence or misconduct.  Under the terms of the drilling and operating agreement, PDC may subcontract responsibilities as operator for Partnership wells.  PDC retains responsibility for work performed by subcontractors.

To the extent the Partnership has less than a 100% working interest in a well, the Partnership pays only a proportionate share of total lease, development, and operating costs, and receives a proportionate share of production subject only to royalties and overriding royalties. The Partnership is responsible only for its obligations and is liable only for its proportionate working interest share of the costs of developing and operating the wells.

The operator provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and deducts from Partnership revenues a 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 rates, which vary based upon the area 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 average of the then current 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 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.

The Partnership has the right to take in kind and separately dispose of its share of all oil and gas produced from its wells.  The Partnership designated PDC as its agent to market its production and authorized PDC to enter into and bind the Partnership in those agreements as it deems in the best interest of the Partnership for the sale of its oil and/or gas.  If pipelines owned by PDC are used in the delivery of gas to market, PDC charges a gathering fee not to exceed that which would be charged by a non-affiliated third party for a similar service.

The drilling and operating agreement continues in force as long as any well or wells produce, or are capable of 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 Agreement.

Production Phase of Operations

General When Partnership wells are "complete" (i.e., drilled, fractured or stimulated, and all surface production equipment and pipeline facilities necessary to produce the well are installed), production operations commence on each well.

The Partnership sells the produced gas to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of gas sold varies as a result of market forces.  Some leases, and thus the gas derived from wells drilled on those leases, may be dedicated to particular markets at the time the Partnership acquired those leases, or subsequent to, as part of the gas marketing arrangements.

PDC, on behalf of the Partnership, may enter into fixed price contracts, or utilize derivatives, including hedges, swaps or options in order to offset some or all of the price variability for particular periods of time, generally for less than two years.  The use of derivatives may entail fees, including the time value of money for margin requirements, which are charged to the Partnership.

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Seasonal factors, such as effects of weather on prices received and costs incurred, may impact the Partnership's results.  In addition, both sales volumes and prices tend to be affected by demand factors with a significant seasonal component.

Revenues, Expenses and Distributions

The Partnership's share of production revenue from a given well is burdened by and/or subject to royalties and overriding royalties, monthly operating charges, taxes and other operating costs.

The above items of expenditure involve amounts payable solely out of and expenses incurred solely by reason of production operations.  Although the Partnership is permitted to borrow funds for its operations, it is PDC's practice to deduct operating expenses from the production revenue for the corresponding period and to defer the collection of operating expenses to future periods when revenues are insufficient to render full payment.

Interests of Parties in Production Revenues

PDC, the Investor Partners, and unaffiliated third parties (including landowners) share revenues from production of gas and oil from wells in which the Partnership has an interest.  The following chart illustrates the interest of gross revenues derived from the wells.  For the purpose of this chart, "gross revenue" is defined as the "wellhead gas and oil revenue" paid by the purchasers.  Landowner and other royalties payable to unaffiliated third parties may vary, generally between 12.5% to 25% or more; however, the average of the royalty interests for all prospects or wells of the Partnership may not exceed 25%.

Illustration of Partnership Revenue Sharing
Entity or Interest Owners	Partnership Interests	Gross Revenue Interests (Partnership Revenues and Third Party Royalties)
		If 12½% Royalty:	If 25% Royalty:
PDC, the Managing General Partner	37%	32.375%	27.75%
Investor Partners	63%	55.125%	47.25%
Landowners and Over- riding Royalty Owners	N/A	12.50%	25.00%
Totals	100%	100.00%	100.00%

Insurance

PDC, in its capacity as operator, carries well pollution, public liability and worker’s compensation insurance for its own benefit as well as the benefit of the Partnership, but that insurance may not be sufficient to cover all liabilities.  Each unit held by the general partners, excluding the Managing General Partner, represents an open-ended security for unforeseen events such as blowouts, lost circulation, and stuck drill pipe, which may result in unanticipated additional liability materially in excess of the per unit subscription amount.

PDC has obtained various insurance policies, as described below, and intends to maintain these policies subject to PDC's analysis of their premium costs, coverage and other factors.  PDC may, in its sole discretion, increase or decrease the policy limits and types of insurance from time to time as deemed appropriate under the circumstances, which may vary materially.  PDC is the beneficiary under each policy and pays the premiums for each policy, except with respect to the insurance coverage referred to in items 2 and 5 below in which case the Managing General Partner and the Partnership are co-insured and co-beneficiaries.  Additionally, PDC as operator of the Partnership's wells requires all of PDC's subcontractors to carry liability insurance coverage with respect to their activities.  In the event of a loss, the insurance policies of the particular subcontractor at risk would be drawn upon before the insurance of the Managing General Partner or that of the Partnership.  PDC has obtained and expects to maintain the following insurance.

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1. Worker's compensation insurance in full compliance with the laws for the states in which the operator has employees;

2. Operator's bodily injury liability and property damage liability insurance, each with a limit of $1,000,000;

3. Employer's liability insurance with a limit of not less than $1,000,000;

4. Automobile public liability insurance with a limit of not less than $1,000,000 per occurrence, covering all automobile equipment; and

5. Operator's umbrella liability insurance with a limit of $50,000,000 for each well location and in the aggregate.

PDC believes that 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 drilling. PDC has maintained liability insurance, including umbrella liability insurance, of at least two times the Partnership’s capitalization, up to a maximum of $50,000,000, but in no event less than $10,000,000 during drilling operations.

Competition and Markets

Competition is high among persons and companies involved in the exploration for and production of oil and gas.  The Partnership competes with entities having financial resources and staffs substantially larger than those available to the Partnership.  There are thousands of oil and gas companies in the United States.  The national supply of gas is widely diversified.  As a result of this competition and FERC and Congressional deregulation of oil and gas prices, prices are generally determined by competitive forces.

The marketing of any oil and gas produced by the Partnership is affected by a number of factors 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 pipeline and other transportation facilities, the proximity of the wells to the refineries, the marketing of competitive fuels, such as coal and nuclear 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 crude oil and gas in world markets has caused significant variations in the prices of these products over recent years.

FERC Order No. 636, issued in 1992, restructured the gas industry by requiring pipelines to separate their storage, sales and transportation functions and establishing an industry-wide structure for "open-access" transportation service.  FERC Order No. 637, issued in February 2000, further enhanced competitive initiatives, by removing price caps on short-term capacity release transactions.

FERC Order No. 637 also enacted other regulatory policies that increase the flexibility of interstate gas transportation, maximize shippers' supply alternatives, and encourage domestic gas production in order to meet projected increases in gas demand.  These increases in demand come from a number of sources, including as boiler fuel to meet increased electric power generation needs and as an industrial fuel that is environmentally preferable to alternatives such as nuclear power and coal.  This trend has been evident over the past year, particularly in the western United States, where gas is the preferred fuel for environmental reasons, and electric power demand has directly affected demand for gas.

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The combined impact of FERC Order 636 and 637 has been to increase the competition among gas suppliers from different regions.

In 1995, the North American Free Trade Agreement ("NAFTA") eliminated trade and investment barriers in the United States, Canada, and Mexico, increasing foreign competition for gas production.  Legislation that Congress may consider with respect to oil and gas may increase or decrease the demand for the Partnership's production in the future, depending on whether the legislation is directed toward decreasing demand or increasing supply.

Members of the Organization of Petroleum Exporting Countries (“OPEC”) establish prices and production quotas for petroleum products from time to time, with the intent of reducing the current global oversupply and maintaining or increasing price levels.  PDC is unable to predict what effect, if any, future OPEC actions will have on the quantity of, or prices received for, oil and gas produced and sold from the Partnership's wells.

Various parts of the fields where the Partnership’s wells are located are crossed by pipelines belonging to Colorado Interstate Gas, Encana, DCP Midstream (“DCP” formerly Duke Energy), Williams Production RMT (Williams) and others.  These companies have all traditionally purchased substantial portions of their supply from Colorado producers.  Transportation on these systems requires that delivered gas meet quality standards and that a tariff be paid for quantities transported.

Sales of gas from the Partnership's wells to DCP and Williams are made on the spot market via open access transportation arrangements through Colorado Interstate Gas, Williams or other pipelines.  As a result of FERC regulations that require interstate gas pipelines to separate their merchant activities from their transportation activities and require them to release available capacity on both a short and a long-term basis, local distribution companies must take an increasingly active role in acquiring their own gas supplies.  Consequently, pipelines and local distribution companies are buying gas directly from gas producers and marketers, and retail unbundling efforts are causing many end-users to buy their own reserves.  Activity by state regulatory commissions to review local distribution company procurement practices more carefully and to unbundle retail sales from transportation has caused gas purchasers to minimize their risks in acquiring  gas supply and has added to competition in the gas marketplace.

Gas and Oil Pricing

PDC sells the gas and oil from Partnership wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond the control of the Partnership.  Currently, PDC sells Partnership gas in the Piceance Basin primarily to Williams, which has an extensive gathering and transportation system in the field.  In the Wattenberg Field, the gas is sold primarily to DCP, which gathers and processes the gas and liquefiable hydrocarbons produced.  Gas produced in Colorado is subject to changes in market prices on a national level, as well as changes in the market within the Rocky Mountain Region.  Sales may be affected for short periods of time by capacity interruptions on pipelines transporting gas out of the region.

Currently, PDC sells 100% of the oil from the Partnership’s wells to Teppco Crude Oil, L.P.  Generally, the oil is picked up at the well site and trucked to either refineries or oil pipeline interconnects for redelivery to refineries. Oil prices fluctuate not only with the general market for oil as may be indicated by changes in the New York Mercantile Exchange (“Nymex”), but also due to changes in the supply and demand at the various refineries. Additionally, the cost of trucking or transporting the oil to market affects the price the Partnership ultimately receives for the oil.

Governmental Regulation

While the prices of oil and gas are set by the market, other aspects of the Partnership’s business and the oil and gas industry in general are heavily regulated.  The availability of a ready market for oil and gas 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 oil and gas 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 oil and gas, to prevent waste of oil and gas, to protect rights between 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.  The Partnership takes the steps necessary to comply with applicable regulations.  The Partnership 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 United States oil and 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.

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Environmental Regulations

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 could 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 gas industry in general, the Partnership’s business and prospects could be adversely affected.

The Partnership generates wastes that may be subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes.  The United States 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.

Proposed Regulation

Various legislative proposals and proceedings that may affect the oil and 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 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, regulatory requirements relating to climate change and/or tax incentives and other measures.  The oil and 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.

Operating Hazards

The Partnership’s production operations include a variety of operating risks, including the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of toxic gas.  The occurrence of any of these could result in substantial losses to the Partnership 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 pipeline, gathering and distribution operations are subject to the many hazards inherent in the gas 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 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 its ability to conduct its 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 its purchase or whether insurance will be available at all.  Furthermore, the Partnership is not insured against its 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 adversely affect the Partnership’s ability to deliver gas.

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Available Information

The Partnership 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, that the Partnership files electronically with the SEC.  The address of that site is http://www.sec.gov.  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.  The Central Index Key, or CIK, for the Partnership is 0001407805.

Item 1A Risk Factors

In the course of its normal business, the Partnership is subject to a number of risks that could adversely impact its business, operating results, financial condition, and cash distributions.  The following is a discussion of the material risks involved in an investment in the Partnership.

Risks Pertaining to Gas and Oil Investments

The oil and gas business is speculative and may be unprofitable and result in the total loss of investment.  The oil and gas business is inherently speculative and involves a high degree of risk and the possibility of a total loss of investment.  The Partnership's business activities may result in unprofitable well operations, not only from non-productive wells, but also from wells that do not produce oil or gas in sufficient quantities or quality to return a profit on the amounts expended.  The prices of oil and gas play a major role in the profitability of the Partnership.  Partnership wells may not produce sufficient gas and oil for investors to receive a profit or even to recover their initial investment.  Only three of the prior Partnerships sponsored by PDC have, to date, generated cash distributions in excess of investor subscriptions without giving effect to tax savings.

The Partnership may retain Partnership revenues or borrow funds if needed for Partnership operations to fully develop the Partnership's wells; if full development of the Partnership's wells proves commercially unsuccessful, an investor may anticipate a reduction in cash distributions.  The Partnership utilized substantially all of the capital raised in the offering for the drilling and completion of wells.  As indicated under Plan of Operations, PDC plans to recomplete most of the wells producing from the Codell formation in the Wattenberg Field after they have produced for five years or more.  PDC will charge the Partnership for the direct cost of recompletions.  In order to obtain the required additional capital for the Codell formation recompletions in the future, PDC will have to either retain Partnership revenues or borrow the funds necessary for these purposes.  Retaining Partnership revenues and/or the repayment of borrowed funds will result in a reduction of cash distributions to the investors.  Additionally, in the future, PDC may wish to rework or recomplete additional Partnership wells; however, PDC has not held money from the initial investment for that future work.  Future development of the Partnership's wells may prove commercially unsuccessful and the further-developed Partnership wells may not generate sufficient funds from production to increase distributions to the investors to cover revenues retained or to repay financial obligations of the Partnership for borrowed funds plus interest.  If future development of the Partnership's wells is not commercially successful, whether using funds retained from production revenues or borrowed funds, these operations could result in a reduction of cash distributions to the Investor Partners of the Partnership.

Increases in prices of oil and gas have increased the cost of drilling and development and may affect the performance and profitability of the Partnership in both the short and long term.  In the current high price environment, most oil and gas companies have increased their expenditures for drilling new wells.  This has resulted in increased demand and higher cost for oilfield services and well equipment.  Because of these higher costs, the risk to the Partnership of decreased profitability from future decreases in oil and gas prices is increased.

Reductions in prices of oil and gas reduce the profitability of the Partnership's production operations and could result in reduced cash distributions to the investors.  Global economic conditions, political conditions, and energy conservation have created unstable prices.  Revenues of the Partnership are directly related to gas and oil prices.  The prices for domestic gas and oil production have varied substantially over time and by location and are likely to remain extremely unstable.  Revenue from the sale of oil and gas increases when prices for these commodities increase and declines when prices decrease.  These price changes can occur rapidly and are not predictable and are not within the control of the Partnership.  A decline in gas and/or oil prices would result in lower revenues for the Partnership and a reduction of cash distributions to the Investor Partners of the Partnership.  Further, reductions in prices of oil and gas may result in shut-ins, thereby resulting in lower production, revenues and cash distributions.

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The high level of drilling activity could result in an oversupply of gas on a regional or national level, resulting in much lower commodity prices, reduced profitability of the Partnership and reduced cash distributions to the investors.  Recently, the gas market has been characterized by excess demand compared to the supplies available, leading in general to higher prices for gas.  The high level of drilling, combined with a reduction in demand resulting from higher prices, could result in an oversupply of gas.  In the Rocky Mountain region, rapid growth of production and increasing supplies may result in lower prices and production curtailment due to limitations on available pipeline facilities or markets not developed to utilize or transport the new supplies.  In both cases, the result would probably be lower prices for the gas the Partnership produces, reduced profitability for the Partnership and reduced cash distributions to the Investor Partners.  To demonstrate this point, in the third and fourth quarter of 2007, the price of gas in the Rocky Mountains region declined over the same periods in 2006.

Sufficient insurance coverage may not be available for the Partnership, thereby increasing the risk of loss for the Investor Partners.  It is possible that some or all of the insurance coverage which the Partnership has available may become unavailable or prohibitively expensive.  In that case, PDC might elect to change the insurance coverage.  The general partners, excluding the Managing General Partner, could be exposed to additional financial risk due to the reduced insurance coverage and due to the fact that they would continue to be individually liable for obligations and liabilities of the Partnership that arise prior to conversion to limited partners. Investor Partners could be subject to greater risk of loss of their investment because less insurance would be available to protect the Partnership from casualty losses.  Moreover, should the Partnership's cost of insurance become more expensive, the amount of cash distributions to the investors will be reduced.

Through their involvement in the Partnership and other non-partnership activities, the Managing General Partner and its affiliates have interests which conflict with those of the Investor Partners; actions taken by the Managing General Partner in furtherance of its own interests could result in the Partnership being less profitable and a reduction in cash distributions to the Investor Partners.  PDC's continued active participation in oil and gas activities for its own account and on behalf of other partnerships organized or to be organized by PDC and the manner in which Partnership revenues are allocated create conflicts of interest with the Partnership.  PDC has interests which inherently conflict with the interests of the Investor Partners.  The following is an itemization of the material conflicts of interest of PDC as Managing General Partner of the Partnership and of PDC’s affiliates:

· PDC might sponsor additional drilling programs in the future that could conflict with the interests of the Partnership.  PDC and affiliates have the right to organize and manage oil and gas drilling programs in the future similar to the Partnership and to conduct production operations now and in the future on its own behalf or for other investors.  This situation could lead to a conflict between the position of PDC as Managing General Partner of the Partnership and the position of PDC or its affiliates as managing general partner or sponsor of additional programs.

· PDC has a fiduciary duty as Managing General Partner to the Partnership.  PDC acts as managing general partner currently for 33 limited partnerships, including this Partnership, and is accountable to all of the partnerships as a fiduciary.  PDC therefore has a duty to exercise good faith and deal fairly with the investors of each partnership.  PDC’s actions taken on behalf of one or more of these partnerships could be disadvantageous to the Partnership and could fall short of the full exercise of its fiduciary duty to the Partnership.

· There are and will continue to be transactions between PDC, its affiliates and the Partnership.  PDC, as operator of the Partnership, has and will continue to provide drilling, completion and operation services to the Partnership’s wells.  Although the prices that PDC has charged, and will charge, to the Partnership for the supplies and services provided by PDC and affiliates to the Partnership will be competitive with the prices charged by unaffiliated persons for the same supplies and services, PDC will benefit financially from this relationship.

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In operating the Partnership, the Managing General Partner and its affiliates could take actions which benefit themselves and which do not benefit the Partnership.  These actions could result in the Partnership being less profitable.  In that event, an Investor Partner could anticipate a reduction of cash distributions.

The Partnership and other partnerships sponsored by the Managing General Partner may compete with each other for prospects, equipment, contractors, and personnel; as a result, the Partnership may find it more difficult to operate effectively and profitably.  During 2007, PDC operated and managed other partnerships formed for substantially the same purposes as those of the Partnership.  PDC will operate and manage these partnerships in 2008 and for the foreseeable future.  Therefore, a number of partnerships with unexpended capital funds, including those partnerships formed before and after the Partnership, may exist at the same time.  The Partnership may compete for equipment, contractors, and PDC personnel (when the Partnership is also needful of equipment, contractors and PDC personnel), which may make it more difficult and more costly to obtain services for the Partnership.  In that event, it is possible that the Partnership would be less profitable.  Additionally, because PDC must divide its attention in the management of its own affairs as well as the affairs of the thirty-three (33) limited partnerships PDC has organized in previous programs, the Partnership will not receive PDC's full attention and efforts at all times.

The Partnership's derivative activities could result in reduced revenue and cash flows compared to the level the Partnership might experience if no derivative instruments were in place and reduced cash distributions to the investors.  The Partnership uses derivative instruments for a portion of its gas and oil production to achieve a more predictable cash flow and to reduce exposure to adverse fluctuations in the prices of gas and oil.  These arrangements expose the Partnership to the risk of financial loss in some circumstances, including when purchases or sales are different than expected, the counter-party to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive.  In addition, derivative arrangements may limit the benefit from changes in the prices for gas and oil.  Since our derivatives do not currently qualify for use of hedge accounting, changes in the fair value of derivatives are recorded in our statement of operations, and our net income is subject to greater volatility than if our derivative instruments qualified for hedge accounting.  The market prices for gas and oil, however, have continued to increase since such derivatives were entered; if such market pricing continues, it could result in significant non-cash charges each quarter, which could have a material negative affect on the Partnership’s net income.

Fluctuating market conditions and government regulations may cause a decline in the profitability of the Partnership and a reduction of cash distributions to the Investor Partners.  The sale of any gas and oil produced by the Partnership will be affected by fluctuating market conditions and governmental regulations, including environmental standards, set by state and federal agencies.  From time-to-time, a surplus of gas or oil may occur in areas of the United States.  The effect of a surplus may be to reduce the price the Partnership receives for its gas or oil production, or to reduce the amount of gas or oil that the Partnership may produce and sell.  As a result, the Partnership may not be profitable.  Lower prices and/or lower production and sales will result in lower revenues for the Partnership and a reduction in cash distributions to the Investor Partners.

The Partnership is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.  The Partnership’s operations are regulated extensively at the federal, state and local levels.  Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and gas wells.  Under these laws and regulations, the Partnership could also be liable for personal injuries, property damage and other damages.  Failure to comply with these laws and regulations may result in the suspension or termination of the Partnership’s operations and subject the Partnership to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.  Compliance with these regulations and possible liability resulting from these laws and regulations could result in a decline in profitability of the Partnership and a reduction in cash distributions to the partners of the Partnership.

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The Partnership’s activities are subject to the regulations regarding conservation practices and protection of correlative rights.  These regulations affect our operations and limit the quantity of gas and/or oil the Partnership may produce and sell.  A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities.  Because the Partnership plans to re-complete various of its Wattenberg Wells in approximately five years, for which permits will be required, delays in obtaining regulatory approvals or drilling permits or the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties.  Additionally, the gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our ability to pay distributions to our Investor Partners.  We further reference sections “Government Regulation” and “Proposed Regulation” in “Item 1, Business”, for a detailed discussion of the laws and regulations that affect the Partnership’s activities.

Environmental hazards involved in drilling gas and oil wells may result in substantial liabilities for the Partnership, a decline in profitability of the Partnership and a reduction in cash distributions to the Investor Partners.  There are numerous natural hazards involved in the drilling and operation of wells, including unexpected or unusual formations, pressures, blowouts involving possible damages to property and third parties, surface damages, personal injury or loss of life, damage to and loss of equipment, reservoir damage and loss of reserves.  Uninsured liabilities would reduce the funds available to the Partnership, may result in the loss of Partnership properties and may create liability for additional general partners.  The Partnership may become subject to liability for pollution, abuses of the environment and other similar damages, and it is possible that insurance coverage may be insufficient to protect the Partnership against all potential losses.  In that event, Partnership assets would be used to pay personal injury and property damage claims and the costs of controlling blowouts or replacing destroyed equipment rather than for drilling activities.  These payments would cause an otherwise profitable partnership to be less profitable or unprofitable and would result in a reduction of cash distributions to the partners of the Partnership.

Delay in the partnership production of gas or oil could reduce the Partnership's profitability and result in a reduction in cash distributions to the Investor Partners.  The Partnership’s inability to complete wells in a timely fashion may also result in production delays.  In addition, marketing demands that tend to be seasonal may reduce or delay production from wells.  Wells drilled for the Partnership may have access to only one potential market.  Local conditions including but not limited to closing businesses, conservation, shifting population, pipeline maximum operating pressure constraints, and development of local oversupply or deliverability problems could halt or reduce sales from Partnership wells.  Any of these delays in the production and sale of the Partnership's gas and oil could reduce the Partnership's profitability, and in that event the cash distributions to the partners of the Partnership would decline.

A significant variance from the Partnership’s estimated reserves and future net revenues estimates could adversely affect the Partnership’s cash flows, results of operations and the availability of capital resources and the Partnership’s earnings.  The accuracy of proved reserves estimates and estimated future net revenues from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. Although the estimated proved reserves represent reserves the Partnership reasonably believes it is certain to recover, actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of the Partnership’s oil and gas reserves, which in turn could adversely affect cash flows, results of operations and the availability of capital resources. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond the Partnership’s control. Downward adjustments to the estimated proved reserves could require a write down to the carrying value of the Partnership’s oil and gas properties, which would reduce earnings and partners’ equity.

The present value of proved reserves will not necessarily equal the current fair market value of the estimated oil and gas reserves. In accordance with the reserve reporting requirements of the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the end of the fiscal year. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.

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Seasonal weather conditions may adversely affect the Partnership’s ability to conduct drilling, completion and production activities in some of the areas of operation.  Oil and gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions. In certain areas, drilling and other oil and gas activities are restricted or prevented by weather conditions for up to 6 months out of the year. This limits operations in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay operations and materially increase operating and capital costs and therefore adversely affect profitability, and could result in a reduction of cash distributions to the investors.

Two Colorado lawsuits against PDC, the Managing General Partner of the Partnership, for underpayment of royalties, could financially harm PDC and the Partnership.  A judgment by the Federal Court against PDC could result in lower oil and gas sales revenues for the Partnership, reduced profitability and reduced cash distributions to the investors.  On May 29, 2007, a complaint was filed against PDC in Weld County, Colorado.  The complaint represents a class action against PDC seeking compensation for alleged underpayment of royalties on leases in Colorado, resulting from the alleged miscalculation of costs to produce marketable gas.  The case was moved to Federal Court in June 2007.  A second similar Colorado class action suit was filed against PDC on December 3, 2007.  On January 28, 2008, the Court granted a motion to consolidate the two cases, and on February 29, 2008, the Court approved a 90 day stay in the proceedings while the parties pursued mediation of the matter.

Based on the mediation held on May 28, 2008, and subsequent negotiations, $18,988 had previously been accrued by the Partnership for this litigation for the year ended December 31, 2007, which represents the expected settlement related to all periods prior to 2008.  On October 10, 2008 the court issued preliminary approval of the settlement agreement.  Although the Partnership was not named as a party in the suit, the lawsuit states that it relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s 75 wells in the Wattenberg field subject to the settlement.  The portion of the proposed settlement related to the Partnership’s wells is $23,267 (This amount did not materially exceed the Partnership reserve in place for this litigation.)

Special Risks of an Investment in the Partnership

The partnership units are not registered, there will be no public market for the units, and as a result an Investor Partner may not be able to sell his or her units.  There is and will be no public market for the units nor will a public market develop for the units.  Investor Partners may not be able to sell their Partnership interests or may be able to sell them only for less than fair market value.  The offer and sale of units have not been, and will not in the future be, registered under the Securities Act or under any state securities laws.  Each purchaser of units has been required to represent that such investor has purchased the units for his or her own account for investment and not with a view to resale or distribution.  No transfer of a unit may be made unless the transferee is an "accredited investor" and such transfer is registered under the Securities Act and applicable state securities laws, or an exemption there from is available.  The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with all applicable securities laws.  A sale or transfer of units by an investor requires PDC's prior written consent.  For these and other reasons, an investor must anticipate that he or she will have to hold his or her Partnership interests indefinitely and will not be able to liquidate his or her investment in the Partnership.  Consequently, an investor must be able to bear the economic risk of investing in the Partnership for an indefinite period of time.

Dry hole costs and impairment charges associated with the Partnership's drilling may result in reduced distributions to the investors.  To date, the Partnership has drilled a total of 100 wells.  Of these wells, one has been determined to be commercially unproductive and therefore declared to be a dry hole.  As dry holes result in no production of oil and gas, the occurrence of dry holes causes the revenues and distributions to be less than if the wells drilled had been commercially productive.

Quarterly, the Partnership assesses impairment of capitalized costs of proved oil and gas properties 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 such production to be sold.    Unlike dry holes, impaired properties may still produce oil and gas which can be sold, however the impaired properties may not generate enough production for the Partnership to recoup the amounts invested in the properties.

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The general partners, including the Managing General Partner, are individually liable for Partnership obligations and liabilities that arise prior to conversion to limited partners that are beyond the amount of their subscriptions, Partnership assets, and the assets of the Managing General Partner.  Under West Virginia law, the state in which the Partnership has organized, general partners of a limited partnership have unlimited liability with respect to the Partnership.  Therefore, the additional general partners of the Partnership were liable individually and as a group for all obligations and liabilities of creditors and claimants, whether arising out of contract or tort, in the conduct of the Partnership's operations until such time as the additional general partners converted to limited partners.  Upon completion of the drilling phase of the Partnership's wells, all additional general partners units will be converted into units of limited partner interests and thereafter become limited partners of the Partnership. Irrespective of conversion, the additional general partners will remain fully liable for obligations and liabilities that arose prior to conversion.  Investors as additional general partners may be liable for amounts in excess of their subscriptions, the assets of the Partnership, including insurance coverage, and the assets of the Managing General Partner.

The Managing General Partner may not have sufficient funds to repurchase limited partnership units.  As a result of PDC, the Managing General Partner, being a general partner in several partnerships as well as an actively operating corporation, the Partnership’s net worth is at risk of reduction if PDC suffers a significant financial loss.  Because the investors may request the Managing General Partner to repurchase the units in the Partnership, subject to certain conditions and restrictions, a significant adverse financial reversal for PDC could result in the Managing General Partner’s inability to pay for Partnership obligations or the repurchase of investor units.  As a result, an investor may not be able to liquidate his or her investment in the Partnership.

A significant financial loss by the Managing General Partner could result in PDC's inability to indemnify additional general partners for personal losses suffered because of Partnership liabilities.  As a result of PDC's commitments as Managing General Partner of several partnerships and because of the unlimited liability of a general partner to third parties, PDC's net worth is at risk of reduction if PDC suffers a significant financial loss.  The partnership agreement provides that PDC as the Managing General Partner will indemnify all additional general partners for the amounts of their obligations and losses which exceed insurance proceeds and the Partnership's assets.  Because PDC is primarily responsible for the conduct of the Partnership's affairs, as well as the affairs of other partnerships for which PDC serves as Managing General Partner, a significant adverse financial reversal for PDC could result in PDC's inability to pay for Partnership liabilities and obligations.  The additional general partners of the Partnership might be personally liable for payments of the Partnership's liabilities and obligations.  Therefore, the Managing General Partner's financial incapacity could increase the risk of personal liability as an additional general partner because PDC would be unable to indemnify the additional general partners for any personal losses they suffered arising from Partnership operations.

A substantial part of our gas and oil production is located in the Rocky Mountain Region, making it vulnerable to risks associated with operating in a single major geographic area.  The Partnership’s operations are focused in the Rocky Mountain Region and our producing properties are geographically concentrated in that area.  Because our operations are not geographically diversified, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.  During the second half of 2007, gas prices in the Rocky Mountain Region fell disproportionately compared to other markets, due in part to continuing constraints in transporting gas from producing properties in the region.  Because of the concentration of our operations in the Rocky Mountain Region, such price decreases could have a material adverse effect on our revenue, profitability and cash flow.

Information technology financial systems implementation problems could disrupt our internal business operations and adversely affect our business financial results or our ability to report our financial results.  The Partnership’s Managing General Partner is currently in the process of implementing a new financial software system to enhance operating efficiencies and provide more effective management of our business operations.    Implementations of financial systems and related software carry such risks as cost overruns, project delays and business interruptions, which could increase our expense, have an adverse effect on our business, our ability to report in an accurate and timely manner our financial position and our results of operations and cash flows.

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The Managing General Partner and various limited partnerships sponsored by the Managing General Partner have been delinquent in filing their periodic reports with the SEC.  Consequently, investors are unable to review current financial statements of other Partnerships sponsored by the Managing General Partner as a source of information in evaluating their investment in the Partnership.  PDC and various other limited partnerships which PDC has sponsored and for which PDC serves as the Managing General Partner are subject to reporting requirements of the Securities Exchange Act of 1934.  As a result, PDC and these limited partnerships are obligated to file annual and quarterly reports with the SEC in accordance with the rules of the SEC.  In the course of preparing its financial statements for the quarter ended June 30, 2005, PDC identified accounting errors in prior period financial statements.  As a result, on October 17, 2005, PDC’s Board of Directors, Audit Committee and management concluded that previously issued financial statements could not be relied upon and would be restated.  PDC made similar determinations regarding the financial statements of various limited partnerships which are subject to the Exchange Act obligations and for which PDC serves as the Managing General Partner.  Since then, PDC has become compliant with its Exchange Act filing and reporting obligations.

The various limited partnerships, except for Rockies Region 2007 Limited Partnership and Rockies Region 2006 Limited Partnership, have not filed their amended annual reports for the years ended prior to and including December 31, 2004, if applicable, or their amended reports for the quarter ended March 31, 2005, if applicable, and have not yet filed their quarterly reports for the quarters ended June 30 and September 30, 2005, if applicable, and March 31, June 30, and September 30, 2006, their annual reports for the years ended December 31, 2005, December 31, 2006 and December 31, 2007, and their quarterly reports for the quarters ended March 31, 2007, June 30, 2007, September 30, 2007, March 31, 2008, June 30, 2008 and September 30, 2008. Exceptions to the above include PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and PDC 2004-A Limited Partnership, all of which filed an annual report on Form 10-K for the year or period ended December 31, 2005. Additionally, Rockies Region Private Limited Partnership filed an amendment to their registration statement on Form 10 which included financial statements for the period ended December 31, 2005 and the quarter ended March 31, 2006. Rockies Region Private Limited Partnership also filed a quarterly report on Form 10-Q for the quarter ended June 30, 2006.  These limited partnerships are in the process of correcting their erroneous reports and preparing the quarterly and annual reports that they have not yet filed.  Until these partnerships file their requisite periodic reports, investors will be unable to review the financial statements of the various limited partnerships as an additional source of information they can use in their evaluation of their investment in the Partnership.  Currently the Managing General Partner has in place a compliance effort addressing the delinquent reports of the various limited partnerships.  However, due to the amount of effort and time required to bring the limited partnerships into compliance with Exchange Act periodic reporting requirements, the Partnership and the various limited partnerships may be unable in the future to file their required periodic reports with the Securities and Exchange Commission in a timely manner.  In addition, the June 30, 2008 Form 10-Q for Rockies Region 2007 Limited Partnership was filed on September 30, 2008, which was after the required filing deadline. The September 30, 2008 Form 10-Q for Rockies Region 2007 Limited Partnership will also be filed after the filing deadline of November 14, 2008.

The Managing General Partner identified material weaknesses in its internal control over financial reporting as of December 31, 2007.  Because we rely on the Managing General Partner for our financial reporting, the internal controls over financial reporting for the Partnership may not be effective and may result in a reasonable possibility that a material misstatement in our annual or interim financial statements will not be prevented or detected on a timely basis.  The Managing General Partner identified material weaknesses in its internal control over financial reporting as of December 31, 2007 as follows:  PDC’s management assessed the effectiveness of PDC’s internal control over financial reporting as of December 31, 2007, based upon the criteria established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).  Based on this evaluation, PDC’s management concluded that PDC did not maintain effective internal control over financial reporting as of December 31, 2007 because of the material weaknesses discussed below.  A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of PDC’s annual or interim financial statements will not be prevented or detected on a timely basis.  PDC’s assessment, as of December 31, 2007, identified the following material weaknesses:

· PDC did not maintain effective controls to ensure the completeness, accuracy, validity and restricted access of certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts.  Specifically, PDC has inadequate controls over:  (1) the security and integrity of the data used in the various spreadsheets, (2) access to the spreadsheets, (3) changes to spreadsheet functionality and the related approval process and documentation, and (4) management’s review of the spreadsheets.  These spreadsheets are used in the financial close and reporting process to perform calculations, generate financial data supporting all significant processes and key manual controls, and to compile information to post entries into the general ledger system.  This control deficiency resulted in an audit adjustment to PDC’s consolidated financial statements for the year ended December 31, 2007.  This control deficiency could result in a misstatement of any of PDC’s financial statement accounts and disclosures that would result in a material misstatement of the annual or interim financial statements that would not be prevented or detected in a timely manner.

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· PDC did not have effective policies and procedures, or personnel with sufficient technical expertise to record derivative activities in accordance with generally accepted accounting principles.  Specifically, PDC’s internal control processes did not ensure the completeness and accuracy of the derivative activities in the fourth quarter.  The lack of documented policies and procedures, and the turnover in key personnel, including ineffective management review process, resulted in an audit adjustment to PDC’s consolidated financial statements for the year ended December 31, 2007.  This control deficiency could result in a misstatement of any of PDC’s derivative financial statement accounts and disclosures that would result in a material misstatement of the annual or interim financial statements that would not be prevented or detected in a timely manner.

The Partnership relies on the Managing General Partners for financial reporting.  As a result of the material weaknesses identified by the Managing General Partner in its internal control over financial reporting, there is a reasonable possibility that a material misstatement in the Partnership’s financial statement will not be prevented or detected in a timely manner.  Material misstatements in the Partnership’s financial reporting could result in incorrect distributions to the Partners.

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Item 2 Financial Information

(a) SELECTED FINANCIAL DATA.

The selected financial data for the quarter ended March 31, 2008 is unaudited.  The selected financial data for the period May 22, 2007 (date of inception) to December 31, 2007 presented below has been derived from audited financial statements of the Partnership appearing elsewhere herein.  This information is only a summary and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes thereto contained in this report.

	(Unaudited) Quarter Ended March 31, 2008			Period May22, 2007 (date of inception) through December 31, 2007
Revenues:
Oil and gas sales	$	5,081,092		$	1,160,201
Oil and gas price risk management loss		(6,913,493	)		(319,365	)
Total revenues		(1,832,401	)		840,836
Operating costs and expenses:
Production and operating costs		541,676			121,897
Direct costs		38,899			-
Management fee		-			1,341,043
Depreciation, depletion and amortization		1,312,392			464,341
Accretion of asset retirement obligations		2,626			927
Total operating costs and expenses		1,895,593			1,928,208
Loss from operations		(3,727,994	)		(1,087,372	)
Interest income		38,186			1,320,134
Net  (loss) income	$	(3,689,808	)	$	232,762
Net loss per investor partner unit	$	(520	)	$	(78	)
Expenditures for oil and gas properties	$	-		$	117,651,199
	At March 31, 2008			At December 31, 2007
Total assets	$	124,116,896		$	119,717,487
Oil and gas properties, net	$	116,031,026		$	117,241,574
Working capital	$	1,757,141		$	2,039,074
Partners' equity	$	115,535,197		$	119,225,005

b)           MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Disclosure Regarding Forward Looking Statements

This report contains forward-looking statements regarding our business, financial condition, results of operations and prospects.  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 oil and gas production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures.  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 them.  Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of gas and 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:

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· changes in production volumes, worldwide demand, and commodity prices for petroleum natural resources;

· risks incident to the operation of gas and oil wells;

· future production and development costs;

· the effect of existing and future laws, governmental regulations and the political and economic climate of the United States;

· the effect of gas and oil derivatives activities;

· availability of capital and conditions in the capital markets; and

· losses possible from future litigation.

Further, you are urged to carefully review and consider the disclosures made in this report, including the risks and uncertainties that may affect the Partnership's business as described herein under Item 1A, Risk Factors.  You 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 publicly 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.

Overview

The Partnership was funded on August 31, 2007 with initial contributions of $89,402,885 from the Investor Partners and $38,659,808 from the Managing General Partner.  After payment of syndication costs of $9,070,450 and a one-time management fee to PDC of $1,341,043, the Partnership had available cash of $117,651,200 to commence Partnership oil and gas well drilling activities.

The Partnership began developmental drilling activities immediately after funding.  The Partnership was billed by PDC for development activities from the inception of the Partnership through December 31, 2007.  At December 31, 2007, amounts remaining from the funding of the Partnership were paid to PDC as a prepayment for drilling of oil and gas wells on behalf of the Partnership under the drilling and operating agreement.    As of September 30, 2008, a total of one hundred wells have been drilled, all in Colorado, of which ninety-eight are producing and one is determined to be a developmental dry hole.  It is anticipated that these one hundred wells will be the only wells the Partnership will drill.  Once completed, the wells will produce primarily gas, with some associated crude oil.  Sales of produced gas and oil commenced during the fourth quarter of 2007 as wells were connected to pipelines.  Production and sales are expected to increase in 2008 as additional wells are completed and connected to pipelines.  Once producing, the Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, it is the plan of the Partnership and the Managing General Partner to recomplete the Codell formation in certain wells in the Wattenberg Field after five or more years of production because these wells will have experienced a significant decline in production in that time period.  These Codell recompletions typically increase the production rates and recoverable reserves.  Although PDC’s prior experience with Codell recompletions has seen significant production increases, not all recompletions have been successful.

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Results of Operations

The following table presents significant operational information of the Partnership from the date of inception through March 31, 2008:

	(Unaudited) Period May 22, 2007 (date of inception) through September 30, 2007			(Unaudited) Three month period ended December 31, 2007			Period May 22, 2007 (date of inception) through December 31, 2007			(Unaudited) Three month period ended March 31, 2008
Number of producing wells (end of period)		-			13			13			37
Production:
Oil (Bbl)		-			13,241			13,241			36,813
Natural gas (Mcf)		-			24,330			24,330			280,302
Natural gas equivalents (Mcfe)		-			103,774			103,774			501,180
Average Selling Price
Oil (per Bbl)	$	-		$	76.00		$	76.00		$	84.45
Natural gas (per Mcf)	$	-		$	6.33		$	6.33		$	7.04
Natural gas equivalents (per Mcfe)	$	-		$	11.18		$	11.18		$	10.14
Average cost per Mcfe
Production and operating costs	$	-		$	1.17		$	1.17		$	1.08
Depreciation, depletion and amortization	$	-		$	4.47		$	4.47		$	2.62
Revenues:
Oil sales	$	-		$	1,006,299		$	1,006,299		$	3,108,783
Gas sales		-			153,902			153,902			1,972,309
Oil and gas sales		-			1,160,201			1,160,201			5,081,092
Oil and gas price risk management loss		-			(319,365	)		(319,365	)		(6,913,493	)
Total Revenues		-			840,836			840,836			(1,832,401	)
Operating costs and expenses:
Production and operating costs		-			121,897			121,897			541,676
Direct costs		-			-			-			38,899
Management fee		1,341,043			-			1,341,043			-
Depreciation, depletion and amortization		-			464,341			464,341			1,312,392
Accretion of asset retirement obligations		-			927			927			2,626
Total operating costs and expenses		1,341,043			587,165			1,928,208			1,895,593
(Loss) income from operations		(1,341,043	)		253,671			(1,087,372	)		(3,727,994	)
Interest income		444,499			875,635			1,320,134			38,186
Net (loss) income	$	(896,544	)	$	1,129,306		$	232,762		$	(3,689,808	)

Definitions

· Bbl – One barrel or 42 U.S. gallons liquid volume

· Mcf – One thousand cubic feet

· Mcfe – One thousand cubic feet of gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content.

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Oil and Gas Sales and Operating Costs and Expenses

The results of operations are indicative of the transition from drilling to production activities.  The Partnership had two producing wells in October, nine in November and thirteen in December.  Eight additional wells were brought in line in January 2008, nine in February and six in March.  The Managing General Partner expects to bring the remaining 63 well in line during the second and third quarters of 2008.

61% and 87% of sales revenue for the period ended March 31, 2008 and December 31, 2007, respectively, was derived from oil production.  This high proportion of oil to gas is not uncommon in the early stages of production for wells located in the Wattenberg field and is expected to diminish significantly over time.

In accordance with the Partnership Agreement, the Partnership incurred a one-time management fee, allocated solely to the Investor Partners, of $1,341,043 upon funding of the Partnership.

Depreciation, depletion and amortization expense of $1,371,002 and $464,341 for the periods ending March 31, 2008 and December 31, 2007, respectively, resulted solely from the depletion of oil and gas properties. The increase was attributable to the increase in production due to the additional producing wells.

The Partnership incurred direct costs of $ 38,899 through March 31, 2008. The Partnership expects to incur additional costs relating to auditing and tax services during the remainder of 2008.

Oil and Gas Price Risk Management

Oil and Gas Pricing:Financial results depend upon many factors, particularly the price of oil and gas and our ability to market our production effectively.  Oil and gas prices have been among the most volatile of all commodity prices.  These price variations have a material impact on our financial results.  Oil and gas prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality.  This can be especially true in the Rocky Mountain Region in which all of the partnership wells are located.  The combination of increased drilling activity and the lack of local markets could result in a local market oversupply situation from time to time.  Such a situation existed in the Rocky Mountain Region during 2007, with production exceeding the local market demand and pipeline capacity to non-local markets.  The result, beginning in the second quarter of 2007 and continuing through and into the fourth quarter of 2007, had been a decrease in the price of Rocky Mountain natural gas compared to the NYMEX price and other markets.  The expansion in January 2008 of the Rockies Express pipeline, or REX, resulted in a narrowing of the price difference.  Once the third phase of the expansion of the Rockies Express is completed in 2009, the pipeline capacity is expected to increase by 64% to 1.8 Bcf/per day of natural gas from the region.  Like most producers in the region, we rely on major interstate pipeline companies to construct these facilities to increase pipeline capacity, rendering the timing and availability of these facilities beyond our control.

The price we receive for a large portion of the natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which may include some gas sold at the CIG Index.  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 NYMEX based.

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Oil and Gas Price Risk Management Loss, Net

The following table reflects the primary components of oil and gas price risk management:

	(Unaudited) Three months ended March 31, 2008			Period from May 22, 2007 to December 31, 2007			Change
Oil and gas price risk management
Realized loss:
Oil	$	(262,633	)	$	0		$	(262,633	)
Gas		0			0			0
Total realized loss		(262,633	)		0			(262,633	)
Unrealized loss		(6,650,860	)		(319,365	)		(6,331,495	)
Oil and gas price risk management loss, net	$	(6,913,493	)	$	(319,365	)	$	(6,594,128	)

The Managing General Partner uses oil and natural gas commodity derivative instruments to manage price risk for itself as well as sponsored drilling partnerships including this Partnership.  As volumes produced change, the mix between the Partnership and the other participants will change.

The rapid increases during the first quarter of 2008 to record high oil prices and sharp increases in natural gas prices from December 31, 2007, to March 31, 2008, along with our increased use of derivative contracts and specifically more fixed price swaps caused the increase in realized and unrealized losses in oil and gas price risk management loss.  The $6.9 million in unrealized losses for the three months ended March 31, 2008, is the fair value of the derivative positions as of March 31, 2008, less the fair value as of December 31, 2007, and includes all open positions as of March 31, 2008, for the period from April 2008 until the expiration of the last position, which is December 2010.  The unrealized loss is a non-cash item in the first quarter of 2008 and there will be further gains or losses as prices increase or decrease until the positions are closed.  While the required accounting treatment for derivatives that do not qualify for hedge accounting treatment under SFAS No. 133 results in significant swings in value and resulting gains and losses for reporting purposes over the life of the derivatives, the combination of the settled derivative contracts and the revenue received from the oil and gas sales at delivery are expected to result in a more predictable cash flow stream than would the sales contracts without the associated derivatives.

Oil and Gas Derivative Activities.  Because of uncertainty surrounding gas and oil prices, we have used various derivative instruments to manage some of the impact of fluctuations in prices.  Through December 2010, we have in place a series of floors, ceilings, collars and fixed price swaps on a portion of our gas and oil production.  Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty; however, if the index drops below the floor, the counterparty pays us.

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The following table sets forth our derivative positions in effect as of November 10, 2008, on our share of production by area.

		Floors				Ceilings				Swaps (Fixed Prices)
Month Set	Month	Net Monthly Quantity Gas-Mmbtus Oil-Bbls		Floor Price		Net Monthly Quantity Gas-Mmbtus Oil-Bbls		Ceiling Price		Net Monthly Quantity Gas-Mmbtus Oil-Bbls		Price
Colorado Interstate Gas (CIG) Based Derivatives (Piceance Basin)
Jan-08	Apr 09 - Oct 09		89,205	$	5.75		89,205		8.75
Feb-08	Nov 08 - Mar 09										53,210		8.18
Mar-08	Apr 09 - Oct 09		87,640		5.75		87,640		9.05
May-08	Nov 08 - Mar 09										89,205		7.76
Jun-08	Nov 08 - Mar 09										53,210		8.52
Jul-08	Nov 09-Mar 10										70,425		9.20
Jul-08	Nov 09-Mar 10		100,160		7.50		100,160		11.40
Colorado Interstate Gas (CIG) Based Derivatives (Wattenberg Field)
Jan-08	Apr 09 - Oct 09		38,390		5.75		38,390		8.75
Feb-08	Nov 08 - Mar 09										22,685		8.18
Mar-08	Apr 09 - Oct 09		34,900		5.75		34,900		9.05
May-08	Nov 08 - Mar 09										55,840		7.76
Jun-08	Nov 08 - Mar 09										31,410		8.52
Jul-08	Nov 09-Mar 10										43,625		9.20
Jul-08	Nov 09-Mar 10		62,820		7.50		62,820		11.40
Oil - Nymex Based (Wattenberg Field)
Oct-07	Oct 08 - Dec 08										11,895		84.20
Jan-08	Jan 09 - Dec 09										7,400		84.90
Jan-08	Jan 09 - Dec 09										7,400		85.40
May-08	Jun 08 - Dec 08										8,853		108.05
May-08	Jan 09 - Dec 09										2,960		117.35
May-08	Jan 10 - Dec 10										7,400		92.74
May-08	Jan 10 - Dec 10										7,400		93.17

The Managing General Partner uses oil and gas commodity derivative instruments to manage price risk for itself as well as the Partnership.  The Managing General Partner sets these instruments for itself and the partnership jointly by area of operation.  As volumes produced change, the mix between PDC and the Partnership will change.  The gross volumes in the above table reflect the total volumes hedged for the Partnership by area of operation.  The above table reflects such revisions necessary to present our positions in effect as of November 10, 2008.

Liquidity and Capital Resources

The Partnership had working capital of $1,757,141 and $2,039,074 as of March 31, 2008 and December 31, 2007, respectively, consisting primarily of cash and receivables resulting from interest income, and undistributed production revenues.  The partnership began distributing net production revenues in accordance with the Partnership Agreement during the second quarter of 2008.

The Partnership raised $128,062,693 in contributed capital and after paying $9,070,450 for syndication costs and a one time management fee of $1,341,043 had $117,651,200 available for drilling activities.  Through March 31, 2008 and December 31, 2007, the Partnership had paid $77,698,110 and $50,605,373 for drilling activities, respectively.  On December 31, 2007 under the terms of the Partnership Agreement, the remaining $67,045,826 was advanced to the Managing General Partner to cover future drilling costs. At March 31, 2008, there was still $39,953,089 in advanced drilling costs remaining. No additional funds are expected to be used for drilling activities, therefore no borrowings are anticipated during 2008.

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The Partnership’s operations are expected to be conducted with available funds and revenues generated from oil and gas production activities.  Based on current oil and gas prices and prices set by derivatives, and the Partnership’s anticipated production, the Partnership expects a positive cash flow from operations for the remainer of 2008.  As such, the Partnership’s liquidity may be impacted by fluctuating oil and gas prices, as noted in “Item 1A, Risk Factors.”  Changes in market prices for oil and gas directly affect the level of our cash flow from operations. While a decline in oil and gas prices would affect the amount of cash flow that would be generated from operations, we have oil derivatives in place, as of December 31 2007, covering a portion of our expected oil production, thereby providing price certainty for a portion of our 2008 cash flow.  Additional derivative positions were entered into during the first quarter of 2008 for gas production in both Wattenberg and Grand Valley fields.  Our current hedging positions could change based on changes in oil and gas futures markets, the view of underlying oil and gas supply, demand trends and changes in volumes produced. Our oil and gas hedges as of  March 31, 2008 and December 31, 2007, are detailed in “Note 4 – Derivative Financial Instruments” in the notes to financial statements of this report.

Information related to the oil and gas reserves of the Partnership’s wells is discussed in detail in “Note 7 – Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited).”

No bank borrowings are anticipated during 2008 since no recompletions of the Codell formation in the Wattenberg Field wells are expected to be undertaken by the Partnership until 2011 or later.

Contractual Obligations and Contingent Commitments

The table below sets forth the Partnership's contractual obligations and contingent commitments as of March 31, 2008 and December 31, 2007.

	Payments due by period
Contractual Obligations and Contingent Commitments	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
(Unaudited)
March 31, 2008
Asset Retirement Obligations	$	160,113		-		-		-	$	160,113
Derivative instruments		6,970,225		4,877,368		2,092,857		-		-
Royalty settlement		18,988		18,988		-		-		-
Totals		7,149,326		4,896,356		2,092,857		-		160,113
December 31, 2007
Asset Retirement Obligations		55,643		-		-		-		55,643
Derivative instruments		319,365		319,365		-		-		-
Totals	$	375,008	$	319,365		-		-	$	55,643

Critical Accounting Policies and Estimates

We have identified the following policies as critical to the understanding of results of operations.  This 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 accounting policies are important to the portrayal of the Partnership's financial condition and results of operations and require management's most subjective or complex judgments, and as a result, they are subject to an inherent degree of uncertainty.  In applying those policies, management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates.  Those estimates are based on historical experience, observance 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 Notes to the Financial Statements.  The Partnership's critical accounting policies and estimates are as follows:

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Use of Estimates in Testing for Impairment of Long-Lived Assets

Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired.  In performing the impairment test, the Partnership would estimate the future cash flows associated with individual assets or groups of assets.  Impairment must be recognized when the undiscounted estimated future cash flows are less than the related asset’s carrying amount.  In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate.  Although cash flow estimates used by the Partnership 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.

Oil and Gas Property Accounting

The Partnership accounts for its oil and gas properties under the successful efforts method of accounting.  Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and gas reserves.  Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves.  The Partnership obtains new reserve reports from independent petroleum engineers annually as of December 31.

Our estimates of proved reserves are based on quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. Annually, we engage independent petroleum engineers to prepare a reserve and economic evaluation of all our properties on a well-by-well basis as of December 31.

The process of estimating and evaluating oil and gas 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 our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income.

Exploratory well drilling costs are initially capitalized but charged to expense if the well is determined to be nonproductive.  The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting.  Cumulative costs on in-progress exploratory wells (“Suspended Well Costs”) remain capitalized until their productive status becomes known.  If an in-progress exploratory well is found to be unsuccessful (referred to as a dry hole) prior to the issuance of financial statements, the costs are expensed to exploratory dry hole costs.  If a final determination about the productive status of a well cannot be made prior to issuance of the financial statements, the well is classified as Suspended Well Costs until there is sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained.  When a final determination of a well’s productive status is made, the well is removed from the suspended well status and the proper accounting treatment is recorded.  The determination of an exploratory well's ability to produce is made within one year from the completion of drilling activities.

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Upon sale or retirement of significant portions of or complete fields of depreciable or depletable property, the book value thereof, less proceeds, is credited or charged to income.  Upon sale of a partial unit of property, the proceeds are credited to property costs.

The Partnership assesses impairment of capitalized costs of proved oil and gas properties 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 such products will be sold.  These estimates of future product prices may differ from current market prices of oil and gas.  Any downward revisions to the Partnership's estimates of future production or product prices could result in an impairment of the Partnership's oil and gas properties in subsequent periods. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

Revenue Recognition

Sales of gas are recognized when gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.  Gas 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 contracts’ 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 gas and prevailing supply and demand conditions, so that the price of the gas fluctuates to remain competitive with other available gas supplies.  As a result, the Partnership’s revenues from the sale of gas will suffer if market prices decline and benefit if they increase.  However, the Managing General Partner may from time to time enter into derivative agreements, usually with a term of two years or less which may either fix or collar a price in order to reduce the impact of market price fluctuations. The Partnership believes that the pricing provisions of its gas contracts are customary in the industry.

The Partnership currently uses the “Net-Back” method of accounting for transportation arrangements of gas sales.  The Partnership sells gas at the wellhead, collects a price, 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.

Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured, and the sales price is determinable.  The Partnership does not refine any of its oil production.  The Partnership’s crude oil production is sold to purchasers 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.

Asset Retirement Obligations

The Partnership applies the provisions of SFAS 143, “Accounting for Asset Retirement Obligations” and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”, and accounts for asset retirement obligations by recording the fair value of its plugging and abandonment obligations when incurred, which is at the time the well is completely drilled.  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 asset retirement obligations are accreted, over the estimate life of the related asset, for the change in their present value.  The initial capitalized costs are depleted over the useful lives of the related assets, through charges to depreciation, depletion and amortization.  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 asset retirement obligations.  See “Note 8 – Asset Retirement Obligations” for a reconciliation of asset retirement obligation activity.

Accounting for Derivatives Contracts at Fair Value

The Partnership uses derivative instruments to manage its commodity market risks.  The Partnership currently does not use hedge accounting treatment for its derivatives.  Derivatives are reported on the accompanying balance sheets at fair value on a gross asset and liability basis.  Changes in fair value of derivatives are recorded in oil and gas price risk management, net, in the accompanying statements of operations.  The measurement of fair value is based on actively quoted market prices, if available.  Otherwise, validation of a contract's fair value is performed internally and, while the Partnership uses common industry practices to develop its valuation techniques, changes in its pricing methodologies or the underlying assumptions could result in significantly different fair values.  If pricing information from external sources is not available, measurement involves the use of judgment and estimates.  These estimates are based on valuation methodologies the Partnership considers appropriate.  For individual contracts, the use of different assumptions could have a material effect on the contract's estimated fair value.

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Recent Accounting Standards

See “Note 2 – Summary of Significant Accounting Policies” in the Notes to the Financial Statements included in this report for recently issued and implemented accounting standards.

(c) QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Partnership's primary market risk exposure is commodity price risk.

Commodity Price Risk

The Partnership is exposed to the effect of market fluctuations in the prices of oil and gas as they relate to our oil and gas sales.  Price risk represents the potential risk of loss from adverse changes in the market price of oil and gas commodities. We employ established policies and procedures to manage the risks associated with these market fluctuations using commodity derivatives.  Our policy prohibits the use of oil and gas derivative instruments for speculative purposes.

Derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership.  None of the Partnership’s derivative instruments are designated as hedging instruments in accordance with the provision of FAS Statement No. 133, Accounting for Derivative Instruments and Certain Hedging Activities.  Accordingly, all gains and losses, realized and unrealized, are recognized in the statement of operations in the period of change.  See “Note 2 – Summary of Significant Accounting Policies”, and “Note 4 – Derivative Financial Instruments” in the notes to  financial statements included in this report for additional disclosure regarding the Partnership’s derivative instruments including, but not limited to, a summary of the open derivative positions as of March 31, 2008.  Changes in the fair value of the Partnership’s share of derivatives are recorded in the statement of operations under oil and gas price risk management.

Validation of a contract’s fair value is performed by the Managing General Partner, who uses common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

Risk Management Strategies

The results of the Partnership’s operations and operating cash flows are affected by changes in market prices for oil and gas. To mitigate a portion of the exposure to adverse market changes, the Managing General Partner has entered into various derivative instruments on behalf of the Partnership.  As of March 31, 2008 and December 31, 2007, our oil and gas derivative instruments were comprised of futures, fixed-price swaps and collars.  These instruments generally consist of CIG-based contracts for Colorado gas production and NYMEX-based swaps for our Colorado oil production.

· For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

· Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the fixed put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.

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The Partnership purchases puts and set collars to protect against price declines in future periods while retaining much of the benefits of price increases.  While these derivatives are structured 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 changes in the physical market. The Partnership believes its derivative instruments continue to be effective in achieving the risk management objectives for which they were intended.

The following table presents monthly average CIG and NYMEX closing prices for gas and oil for the first quarter of 2008 and in 2007 as well as average sales prices we realized for the respective commodity.

Average index closing price	(Unaudited) Quarter Ended March 31, 2008		Period from May 22, 2007 to December 31, 2007
Natural gas (per Mcf) - CIG	$	7.33	$	3.97
Oil (per Bbl) - NYMEX	$	81.14	$	69.79

Average sales price	(Unaudited) Quarter ended March 31, 2008		Period from May 22, 2007 to December 31, 2007
Natural gas	$	7.04	$	6.33
Oil	$	84.45	$	76.00

As of March 31, 2008 and December 31, 2007, the fair value of the Partnership’s derivative instruments was a net liability of $6,970,225 and $319,365, respectively.  Based on a sensitivity analysis as of March 31, 2008 and December 31, 2007, it was estimated that a 10% increase in oil and gas prices over the entire period for which we have derivatives currently in place would have resulted in an increase in unrealized losses of $7,828,700 and $330,000, respectively, and a 10% decrease in oil and gas prices would have resulted in a decrease in unrealized losses of $ 8,420,500 and $330,000, respectively.

Disclosure of Limitations

As the information above incorporates only those exposures that exist at March 31, 2008, it does not consider those exposures or positions which could arise after that date.  As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations depends on the future exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.

Item 3 Properties

The Partnership’s properties consist of working interests in gas wells and the ownership in leasehold acreage in the spacing units for the one hundred wells drilled by the Partnership.  The acreage associated with the spacing units is designated by state rules and regulations in conjunction with local practice.  See the sections titled “Drilling Activities” and “Plan of Operations” in “Item 1, Business” for additional information on the Partnership’s properties.

The Partnership commenced drilling activities immediately following funding on August 31, 2007, and as of September 30, 2008, one hundred developmental wells had been drilled, ninety-eight of which were fractured and producing and one of which was determined to be a dry hole.

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As of September 30, 2008, a total of 100 gross wells (99.981 net wells) had been drilled and the status as of that date is reflected in the table below.

	Gross Wells
Drilled, fractured and producing	98
Drilled to depth, not yet fractured	1
Dry hole	1
Total	100

It is anticipated that the one hundred developmental wells drilled will be the only wells drilled by the Partnership. All of the Partnership wells are located in Colorado, seventy-five are located in the Wattenberg field (DJ Basin) and twenty-five are located in the Grand Valley field (Piceance Basin).

Production

Production commenced during the fourth quarter of 2007.  For the quarters ended March 31, 2008 and December 31, 2007, total production net to the Partnership’s interest was 280,302 and 24,330 thousand cubic feet (Mcf) of gas and 36,813 and 13,241 barrels (Bbls) of oil, respectively.

Oil and Gas Reserves

All of the Partnership’s gas and oil reserves are located in the United States.  The Partnership utilized its internal petroleum engineering department for the March 31, 2008 reserve report and utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. for its 2007 reserve report.  The independent engineer’s estimates are made using available geological and reservoir data as well as production performance data. The estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance. 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, oil and gas production, well test data, historical costs of operations and developments, product prices, or any agreements relating to current and future operations of properties and sales of production.  The Partnership's independent reserve estimates are reviewed and approved by the Managing General Partner's internal engineering staff and management.  The Partnership has not filed any estimates of total, proved net oil or gas reserves or included such information in reports to any Federal authority or agency since the date of inception.   See “Note 9 – Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited)” to the financial statements for additional information regarding the Partnership’s reserves.

Title to Properties

The Partnership holds record title in its name to the working interest in each well.  PDC provides an assignment of working interest for the well bore prior to the spudding of the well and effective the date of the spudding of the well, to the Partnership in accordance with the Drilling and Operation Agreement.  Upon completion of the drilling of all of the Partnership wells, these assignments are recorded in the applicable County.  Partnership investors rely on PDC to use its best judgment to obtain appropriate title to these working interests.  Provisions of the limited partnership agreement relieve PDC from any error in judgment with respect to the waiver of title defects.  PDC takes those steps it deems necessary to assure that title to the working interests is acceptable for purposes of the Partnership.

The Partnership's leases are direct interests in producing acreage.  The Partnership believes it holds good and defensible title to its developed properties, in accordance with standards generally accepted in the oil and gas industry. As is customary in the industry, a perfunctory title examination is conducted at the time the undeveloped properties are acquired.  Prior to the commencement of drilling operations, a title examination is conducted and curative work is performed with respect to discovered defects which are deemed to be significant. Title examinations have been performed with respect to substantially all of the Partnership's producing properties.

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The Partnership’s properties are subject to royalty, overriding royalty and other outstanding interests customary to the industry.  The properties may also be subject to additional burdens, liens or encumbrances customary to the industry.  We do not believe that any of these burdens will materially interfere with the use of the properties.

Item 4 Security Ownership of Certain Beneficial Owners and Management

As of September 30, 2008 and December 31, 2007, the Partnership had 4,470 units outstanding.  No director or officer of PDC owns any units.  Subject to certain conditions, Investor Partners may present their units to PDC for purchase.  Pursuant to the Partnership Agreement, PDC is not obligated to purchase more than 10% of the total outstanding units in any calendar year.  As of September 30, 2008, PDC has not repurchased any Partnership interests.  PDC owns a 37% partnership interest in the Partnership.

Item 5 Directors and Executive Officers and Corporate Governance

The Partnership has no directors or executive officers.  The Partnership is managed by Petroleum Development Corporation (“PDC”), the Managing General Partner.

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."  Since 1969, PDC has been engaged in the business of exploring for, developing and producing oil and gas primarily in West Virginia, Tennessee, Pennsylvania, Ohio, Michigan and the Rocky Mountains.  As of December 31, 2007, PDC had approximately 260 employees.  PDC will make available to Investor Partners, upon request, audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods.  PDC's Internet address is www.petd.com.  PDC posts on its Internet Web site its periodic and current reports and other information, including its audited financial statements, that it files with the Securities and Exchange Commission, as well as various charters and other corporate governance information.

As the Managing General Partner, PDC actively manages and conducts the business of the Partnership.  PDC has the full and complete power to do any and all things necessary and incident to the management and conduct of the Partnership's business.  PDC is responsible for maintaining Partnership bank accounts, collecting Partnership revenues, making distributions to the partners, delivering reports to the partners, and supervising the drilling, completion, and operation of the Partnership's gas and oil wells.  The executive officers of PDC are full-time employees of PDC.  As such, they devote the entirety of their daily time to the business and operations of PDC.  One of the major business segments of PDC includes the operation of the business of PDC's sponsored limited partnerships, including the Partnership.  An element of their job responsibilities requires that they devote such time and attention to the business and affairs of the Partnership as is reasonably required.  This time commitment varies for each individual and varies over the life of the Partnership.

In addition to managing the affairs of the Partnership, the management and technical staff of PDC also manage the corporate affairs of PDC, the affairs of thirty-three (33) limited partnerships formed in the current and previous programs, and other joint ventures formed over the years.  PDC owns an interest in all of the older limited partnerships and wells.  Because PDC must divide its attention and efforts among many unrelated parties, the Partnership does not receive its full attention or efforts at all times, however, PDC believes that it devotes sufficient time, attention and expertise to the Partnership to appropriately manage the affairs of the Partnership.

Although the Partnership has no Code of Ethics, PDC has a Code of Ethics that applies to its senior executive officers.  The Code of Ethics is posted on PDC’s website at www.petd.com.

Experience and Capabilities as Driller/Operator

PDC is contracted to serve as operator for the Partnership wells.  Since 1969, PDC has drilled over 3,100 wells in Colorado, West Virginia, Tennessee, Ohio, Michigan, North Dakota, Utah, Wyoming, and Pennsylvania.  PDC currently operates approximately 4,300 wells.

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PDC employs geologists who develop prospects for drilling by PDC and who help oversee the drilling process.  In addition, PDC has an engineering staff that is responsible for well completions, pipelines, and production operations.  PDC retains drilling subcontractors, completion subcontractors, and a variety of other subcontractors in the performance of the work of drilling contract wells.  In addition to 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 an oil and gas 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.  PDC employs full-time well tenders and supervisors to operate its wells.  In addition, the engineering staff evaluates reserves of all wells at least annually and reviews well performance against expectations.  All services provided by PDC are provided at rates less than or equal to prevailing rates for similar services provided by unaffiliated persons in the area.

Petroleum Development Corporation

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 Expires
Steven R. Williams	57	Chairman and Director	1983	2009
Richard W. McCullough	56	Chief Executive Officer, President and Director	2007	2010
Gysle R. Shellum	56	Chief Financial Officer	-	-
Eric R. Stearns	50	Executive Vice President	-	-
Darwin L. Stump	53	Chief Accounting Officer	-	-
Daniel W. Amidon	47	General Counsel and Secretary	-	-
Barton R. Brookman, Jr.	46	Senior Vice President Exploration and Production	-	-
Vincent F. D'Annunzio	56	Director	1989	2010
Jeffrey C. Swoveland	53	Director	1991	2011
Kimberly Luff Wakim	50	Director	2003	2009
David C. Parke	41	Director	2003	2011
Anthony J. Crisafio	55	Director	2006	2009
Joseph E. Casabona	64	Director	2007	2011
Larry F. Mazza	47	Director	2007	2010

Steven R. Williams was elected Chairman in January 2004 and served as Chief Executive Officer from January 2004 to June 2008. Mr. Williams served as President from March 1983 until December 2004.

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Richard W. McCullough was appointed Chief Executive Officer in June 2008, and has served as President since March 2008. Mr. McCullough was appointed Chief Financial Officer in November 2006 and also served as PDC’s Treasurer from November 2006 until October 2007.  Prior to joining PDC, Mr. McCullough served as an energy consultant from July 2005 to November 2006.  From January 2004 to July 2005, Mr. McCullough served as president and chief executive officer of Gasource, LLC, Dallas, Texas, a marketer of long-term, gas supplies.  From 2001 to 2003, Mr. McCullough served as an investment banker with J.P. Morgan Securities, Atlanta, Georgia, and served in the public finance utility group supporting bankers nationally in all gas matters.  Additionally, Mr. McCullough has held senior positions with Progress Energy, Deloitte and Touche, and the Municipal Gas Authority of Georgia.  Mr. McCullough, a CPA, was a practicing certified public accountant for 8 years.

Gysle R. Shellum, was appointed Chief Financial Officer in November 2008.  Prior to joining PDC, Mr. Shellum served as Vice President, Finance and Special Projects of CrossTex Energy, LP, an energy company with upstream and downstream assets from 2004-2008.  From 2002-2004, Mr. Shellum served as a Director of Value Capital, LLC.  Additionally, he served as Chief Financial and Operating Officer at Financial Trade Solutions, Partner and Chief Financial Officer at Duer Wagner & Co., and as American International Petroleum Corporation’s Chief Financial Officer.  Mr. Shellum began his career as a practicing CPA in Arthur Anderson’s energy group.

Darwin L. Stumpwas appointed Chief Accounting Officer in November 2006.  Mr. Stump has been an officer of PDC since April 1995 and held the position of Chief Financial Officer and Treasurer from November 2003 until November 2006.  Previously, Mr. Stump served as Corporate Controller from 1980 until November 2003.  Mr. Stump, a CPA, was a senior accountant with Main Hurdman, Certified Public Accountants prior to joining PDC.

Eric R. Stearns was appointed Executive Vice President in March 2008.  Prior to his current position, Mr. Stearns served as Executive Vice President Exploration and Production since December 2004, Executive Vice President Exploration and Development from November 2003 until December 2004, and Vice President Exploration and Development from April 1995 until November 2003.  Mr. Stearns joined PDC as a geologist in 1985 after working at Hywell, Incorporated and for Petroleum Consultants.

Daniel W. Amidonwas appointed General Counsel and Secretary in July 2007.  Prior to joining PDC, 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.

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 the 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.

Vincent F. D'Annunzio has served as president of Beverage Distributors, Inc., located in Clarksburg, West Virginia since 1985.

Jeffrey C. Swoveland is the Chief Operating Officer of Coventina Healthcare Enterprises, a medical device company specializing in therapeutic warming and multi-modal treatment systems used in the treatment, rehabilitation and management of pain since May 2007.  Previously, 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, from September 2000 to May 2007.  Prior thereto, Mr. Swoveland held various positions, including Vice-President of Finance, Treasurer and interim Chief Financial Officer with Equitable Resources, Inc., a diversified gas company from 1997 to September 2000.  Mr. Swoveland serves as a member of the board of directors of Linn Energy, LLC, a public, independent gas and oil company.

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.  Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990.

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David C. Parke is a Managing Director in the investment banking group of Boenning & Scattergood, Inc., West Conshohocken, PA, 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 Nicolas.  Mr. Parke serves as a member of the board of directors of Zunicom Inc., a public company providing business communication services to the hospitality industry.

Anthony J. Crisafio, a Certified Public Accountant, serves as an independent business consultant, providing financial and operational advice to businesses and has done so since 1995.  Additionally, Mr. Crisafio has served as the Chief Operating Officer of Cinema World, Inc. from 1989 until 1993 and was a partner with Ernst & Young from 1986 until 1989.

Joseph E. Casabona served as Executive Vice President and member of the Board of Directors of Denver based Energy Corporation of America, or ECA, a natural gas exploration and development company from 1985 to his retirement in May 2007.  Mr. Casabona’s responsibilities included strategic planning as well as executive oversight of the drilling operations in the continental United states and internationally.

Larry F. Mazza has served a Chief Executive Officer of MVB Bank Harrison, Inc., in Bridgeport, West Virginia since March 2005.  Prior to the formation of MVB Bank Harrison, Mr. Mazza served as Senior Vice President Retail Banking Manager for BB&T in West Virginia, where he was employed from June 1986 to March 2005.

The Audit Committee of the Board of Directors is comprised of Directors Swoveland, Crisafio, Parke, Wakim and Casabona.  The Board has determined that the Audit Committee is comprised entirely of independent directors as defined by the NASDAQ rule 4200(a) (15).  Anthony J. Crisafio chairs the Audit Committee.  Mr. Crisafio and the other audit committee members, with the exception of Mr. Parke, qualify as audit committee financial experts and are independent of management.

Item 6 Executive Compensation

The Partnership does not have any employees or executives of its own.  None of PDC's officers or directors receives any direct remuneration, compensation or reimbursement from the Partnership.  These persons receive compensation solely from PDC.  The management fee and other amounts paid the Managing General Partner by the Partnership are not used to directly compensate or reimburse PDC’s officers or directors.  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.

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

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Item 7 Certain Relationships and Related Transactions, and Director Independence

Transactions with the Managing General Partner and Affiliates

The following table summarizes transactions between the Partnership and the Managing General Partner and an Affiliate for the quarter March 31, 2008 and the period May 22, 2007 (date of inception) through December 31, 2007:

	(Unaudited) Period Ended March 31, 2008			Period from May 22, 2007 to December 1, 2007
Transaction
Capital contribution (1)	$	-		$	38,659,808
Syndication costs (2)		-			9,070,450
Management fee (3)		-			1,341,043
Sales of leases (4)		462,067			1,362,738
Drilling costs (4)		23,598,978			43,579,867
Drilling compensation (4)		3,031,692			5,662,768
Advanced drilling costs (4)		(27,092,737	)		67,045,826
Well charges (5)		20,450			13,815
Gas marketing, supplies and equipment (6)		125,092			20,603
Gathering, compression and processing fees (7)		41,150			-
Direct costs (8)		38,899			-
Revenue distribution (9)		-			-

Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.

(1) The Managing General Partner has contributed capital of $38,659,808 to the Partnership as of December 31, 2007 in exchange for the 37% allocation of revenues.  The capital contribution was made in two installments, a $20 million payment on August 31, 2007 with the remainder being paid on October 31, 2007 along with interest of $141,000 at 4.5 per cent.

(2) The Partnership reimbursed PDC Securities Inc. a wholly owned subsidiary of the Managing General Partner, for dealer manager commissions, due diligence costs, marketing and support expenses and wholesaling fees as outlined in the Partnership Agreement.  Costs incurred by PDC between May 22 and August 31, 2007 relating to start-up and organization charges, for which no reimbursement was made, were insignificant.

(3) In accordance with the Partnership Agreement, a one-time management fee equal to 1½% of investors’ subscriptions was charged to the Partnership by the Managing General Partner.  This fee was paid by the Partnership to the Managing General Partner upon funding the Partnership.  The fee is treated as period costs in the year of formation and is non-refundable.

(4) The Partnership entered into the drilling and operating agreement with the Managing General Partner to drill and complete the Partnership's wells at cost plus the Managing General Partner's drilling compensation of 12.6% of the total well cost. Total well cost includes the cost of leases acquired from the Managing General Partner and drilling costs.  The drilling compensation percentage of 12.6% was determined prior to formation of the Partnership and disclosed in the offering documents.  The drilling compensation amounts were calculated using this rate in accordance with the offering documents.  The Managing General Partner sells undeveloped prospects (leases) to the Partnership to drill the Partnership’s wells.  Leases are sold to the Partnership at the lower of the Managing General Partner’s cost to purchase the lease or the leases’ fair market value.   Drilling costs include an overhead charge to the Managing General Partner of 1½% of drilling authority for expenditure (“AFE”) for each well.  On December 31, 2007 the Partnership advanced all remaining financing proceeds to the Managing General Partner to cover future drilling costs.

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If the Managing General Partner provides other services in the drilling and completion of the wells, it charges those services at its cost, not to exceed competitive rates charged in its area of operation and these charges are included in the total well cost when determining the Managing General Partner's drilling compensation.

Cost, when used with respect to services, generally means the reasonable, necessary, and actual expense incurred in providing the services, determined in accordance with generally accepted accounting principles.  The cost of the well also includes all ordinary costs of drilling, testing and completing the well.

The well costs charged to the Partnership are proportionately reduced to the extent the Partnership acquires less than 100% of the working interest in a prospect.  The amount of compensation that the Managing General Partner could earn as a result of these arrangements depends on the degree to which it provides services for the wells, and the number and type of wells that are drilled.  If the Managing General Partner supplies other goods and services to the Partnership, it is required to supply them at cost, and they will be included in the total well costs for determining the Managing General Partner's and the investors' contributions, the division of oil and gas revenues, and calculation of the Managing General Partner's drilling compensation.

(5) Under the drilling and operating agreement, the Managing General Partner, as operator of the wells, receives the following from the Partnership when the wells begin producing:

· 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 at a competitive rate, and

· monthly administration charge for Partnership activities.

During the production phase of operations, the operator receives a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $100 for Partnership accounting, engineering, management, and general and administrative expenses.  The 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 partnership agreement.

The well operating charges cover all normal and regularly recurring operating expenses for the production, delivery, and sale of gas and 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 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.

(6) 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.

(7) Under the limited partnership agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the gas produced by the Partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area from the point the gas from the well is commingled with 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 gas.

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

(9)  The limited partnership agreement provides for the allocation of revenues from gas and oil production 63% to the Investors Partners and 37% to the Managing General Partner.    See “Participation in Costs and Revenues” in Item 9 below.

(10)  Additionally refer to Footnote 4 to Financial Statements “Derivative Financial Instruments” for derivative transactions with the general partner.

Related Party Transaction Policies and Approval

The limited partnership agreement governs related party transactions, including those described above.  We have no written policies or procedures for the review, approval or ratification of transactions with related persons outside the limited partnership agreement.

Director Independence

The Partnership has no directors.  The Partnership is managed by the Managing General Partner.  See Item 5 above.

Item 8 Legal Proceedings

The Registrant is not currently subject to any legal proceedings.

PDC, the Managing General Partner, is subject to certain legal proceedings arising from the normal course of business in its capacity as driller and well operator.  As discussed in “Item 2, Properties, Title to Properties”, properties owned by the Partnership are not subject to claims of the Managing General Partner’s creditors.

Royalty Litigation.  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 Partnership’s Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on gas produced from wells operated by the Managing General Partner in 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 in June 2007. A second similar Colorado class action suit was filed against the Managing General Partner in the U.S. District Court for the District of Colorado on December 2007 by Ted Amsbaugh, et al.  In 2008, the Court granted the plaintiff’s motion to consolidate the action with the Droegemueller Action.

Based on the mediation held in May 2008, and subsequent negotiations, $34,153 had previously been accrued by the Partnership for this litigation for the period ended June 30, 2008, which represented the expected settlement related to all periods through June 30, 2008.  On October 10, 2008 the court issued preliminary approval of the settlement agreement.  Although the Partnership was not named as a party in the suit, the lawsuit states that it relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s 75 wells in the Wattenberg field subject to the settlement.  The portion of the proposed settlement related to the Partnership’s wells through all periods prior to September 30, 2008 is $59,825.  During the third quarter of 2008, an additional amount of $25,672 plus legal costs of $3,022 was recorded to fully accrue for the settlement which the Managing General Partner expects to pay into an escrow account for the Partnership in the fourth quarter of 2008.  Final approval and distribution is expected around March 1, 2009.  These amounts will be deducted from future Partnership distributions.

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Item 9 Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters

At September 30, 2008 and December 31, 2007, the Partnership had 1,778 Investor Partners holding 4,470 units and one Managing General Partner.  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 March 31, 2008, the Managing General Partner has not repurchased any Partnership interests.

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 be able to sell them only for less than fair market value.  The offer and sale of the Investor Partners' interests ("units") have not been registered under the Securities Act or under any state securities laws.  Each purchaser of units was required to represent that such investor was purchasing the units for his or her own account for investment and not with a view to parallel distribution.  No transfer of a unit may be made unless the transferee is an "accredited investor" and such transfer is registered under the Securities Act and applicable state securities laws, or an exemption there from is available.  The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with all applicable securities laws.  A sale or transfer of units by an Investor Partner requires PDC's prior written consent.  For these and other reasons, an investor must anticipate that he or she will have to hold his or her partnership interests indefinitely and will not be able to liquidate his or her investment in the Partnership.  Consequently, an investor 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, if funds are available for distribution.  PDC will make cash distributions of 63% to the Investor Partners and 37% to the Managing General Partner throughout the term of the Partnership.

PDC cannot presently predict amounts of cash distributions, if any, from the Partnership.  However, PDC expressly conditions any distribution upon its having sufficient cash available for distribution.  Sufficient cash available for distribution is defined to generally mean 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 debt instruments or 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 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 investors in prior drilling programs sponsored by PDC, or that any level of cash distributions can be maintained.

In general, the volume of production from producing properties declines with the passage of time.  The cash flow generated by the Partnership's activities and the amounts available for distribution to the Partnership's respective partners will, therefore, decline in the absence of significant increases in the prices that the Partnership receives for its oil and gas production, or significant increases in the production of oil and gas from prospects resulting from the successful additional development of these prospects.  If the Partnership decides to develop its wells further, the funds necessary for that development would come from the Partnership's revenues and/or from borrowed funds.  As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners may decrease.

In general, PDC divides cash distributions 63% to the Investor Partners and 37% to PDC throughout the term of the Partnership.  Cash is distributed to the Investor Partners and PDC as a return on capital, in the same proportion as their interest in the net income of the Partnership.  However, no Investor Partner will receive distributions to the extent the distributions would create or increase a deficit in that partner's capital account.

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PDC intends to develop the Partnership's interests in its prospects only with the proceeds of subscriptions and PDC's capital contributions.  However, these funds may not be sufficient to fund all future well costs, and it may be necessary for the Partnership to retain Partnership revenues for the payment of these costs, or for PDC to advance the necessary funds to the Partnership or for the Partnership to borrow necessary funds.  It is likely that the Partnership's Wattenberg Field, Colorado wells will benefit from recompletion services, generally in five years or longer following initial drilling of those wells.  Recompletion is the process of going into an existing zone which is already producing for a refrac, or going into a new zone at a different depth, all with the objective of increasing the production of oil or gas.  If PDC retains Partnership revenues for the payment of these recompletion or refrac costs, the amount of Partnership funds available for distribution to the partners of the Partnership will decrease correspondingly.  Development work will not include the drilling of any new wells beyond the initial wells that have been drilled.  PDC may retain payment for the recompletion or refrac work from Partnership proceeds in one of two methods:

· PDC will prepare an AFE estimate for the Partnership; PDC will complete the development work and will bill the Partnership for the work performed and will be reimbursed from future production; or

· PDC will prepare an AFE estimate for the Partnership; the Partnership will retain revenues from operations until it has accumulated sufficient funds to pay for the development work, at which time PDC will commence the work, and PDC will be reimbursed as the work progresses from retained revenues.

Should PDC decide to retain Partnership revenues for the payment of recompletion or refract costs, the determination of which option to use will be at PDC's discretion, based on the amount of the anticipated expenditure and the urgency of the necessary work.

The limited partnership agreement also permits the Partnership to borrow funds on behalf of the Partnership for Partnership activities. The Partnership may borrow needed funds, or receive advances, from the Managing General Partner or affiliates of the Managing General Partner or from unaffiliated persons.  On loans or advances made available to the Partnership by the Managing General Partner or affiliates of the Managing General Partner, the Managing General Partner or affiliate may not receive interest in excess of its interest costs, nor may the Managing General Partner or affiliate 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.  The Managing General Partner anticipates that borrowed funds will be utilized to finance Codell recompletion activities (see “Item 1, Business”).  As the Partnership will have to pay interest on borrowed funds, the amount of Partnership funds available for distribution to the partners of the Partnership will be reduced accordingly.

Investors who are independent producers are entitled to claim a percentage depletion deduction against their oil and gas income.  The percentage depletion rate for oil and gas properties is generally 15% of the gross income generated by the property.

PARTICIPATION IN COSTS AND REVENUES

Profits and Losses; Cash Distributions and Sharing Arrangements

The limited partnership agreement provides for the allocation of profits and losses during the production phase of the Partnership and for the distribution of cash available for distribution 63% to the Investor Partners and 37% to PDC, the Managing General Partner.  However, amounts are paid to the 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 foregoing allocation of profits and losses is an allocation of each item of income, gain, loss, and deduction which, in the aggregate, constitute a profit or a loss.

Revenues

Gas and Oil Revenues The limited partnership agreement provides for the allocation of revenues from gas and oil production, 63% to the Investor Partners and 37% to PDC.  However, the partnership sharing arrangements may be revised in the event PDC invests capital above PDC’s required minimum capital contribution to cover additional tangible drilling and lease costs, in which case PDC’s share would increase.  (See “Lease Costs, Tangible Well Costs, and Gathering Line Costs” below)

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Interest Income PDC allocates and credits interest earned on the deposit of operating revenues and revenues from any other sources in the same percentages that oil and gas revenues are then being allocated to the Investor Partners and PDC.

Sale of Equipment PDC allocates all revenues from sales of equipment in the same percentages as oil and gas revenues are then being allocated.

Sale of Productive Properties In the event of the sale or other disposition of a productive well, a lease upon which the well is situated, or any equipment related to that lease or well, PDC will allocate and credit to the Investor Partners and PDC, the gain from the sale or disposition, in the same percentages as oil and gas revenues are then being allocated.  The term "proceeds" above does not include revenues from a royalty, overriding royalty, lease interest reserved, or other promotional consideration reserved by the Partnership in connection with any sale or disposition.  PDC will allocate these revenues to the Investor Partners and PDC in the same percentages as the allocation of oil and gas revenues.

Costs

Lease Costs, Tangible Well Costs, and Gathering Line Costs PDC pays 100% of the costs of leases, tangible well costs and gathering line costs.

PDC pays for its share of all leases, tangible drilling and completion costs, and gathering line costs, but not less than 37% of the well costs excluding PDC’s drilling compensation.  If these costs exceed PDC’s required capital contribution, PDC will increase its capital contribution.  In that event, PDC’s share of all items of profit and loss during the production phase of operations and cash available for distribution would be modified to equal for PDC the percentage arrived at by dividing PDC’s capital contributions by the total well costs, excluding PDC’s drilling compensation; the Investor Partners’ allocations of these items would be changed accordingly.

Intangible Drilling Costs (“IDC”) Intangible drilling costs are costs required to drill a well and prepare the well for production.  These costs have no salvage value.  Items like the cost of drilling and completing the well, the cost of grading the surface, labor costs, and geological costs associated with selecting a well site are intangible well costs. IDC is allocated 100% to the Investor Partners.

Operating Costs Operating costs are the costs at the well level associated with producing and maintaining productive wells, like well tending charges, painting equipment and maintaining access roads.  PDC allocates and charges operating costs of Partnership wells 63% to the Investor Partners and 37% to PDC.

Direct Costs  Direct costs are Partnership level costs, primarily professional fees of the independent auditor and reserve engineer and tax return and other similar costs. PDC allocates and charges direct costs of the Partnership 63% to the Investor Partners and 37% to PDC.

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The table below summarizes the participation of the Investor Partners and PDC, taking account of PDC's capital contribution, in the costs and revenues of the Partnership:

	Investor Partners			Managing General Partner
Partnership Revenue:
Oil and gas sales		63	%		37	%
Oil and gas price risk management gain (loss)		63	%		37	%
Sale of productive properties		63	%		37	%
Sale of equipment		63	%		37	%
Sale of undeveloped leases		63	%		37	%
Interest income		63	%		37	%
Partnership Costs:
Organization costs (a)		0	%		100	%
Broker-dealer commissions and expenses/syndication costs (a)		100	%		0	%
Cost of oil and gas properties:
Undeveloped lease costs		0	%		100	%
Tangible well costs		0	%		100	%
Intangible drilling costs		100	%		0	%
Managing General Partner's drilling compensation		100	%		0	%
Direct drilling and compensation costs, excluding
Managing General Partner’s drilling compensation		63	%		37	%
Other costs and expenses:
Management fee (b)		100	%		0	%
Production and operating costs (c)		63	%		37	%
Depreciation, depletion and amortization expense		63	%		37	%
Accretion of asset retirement obligations		63	%		37	%
Direct costs (d)		63	%		37	%

(a) The Managing General Partner paid all legal, accounting, printing, and filing fees associated with the organization of the Partnership and the offering of units and is allocated 100% of these costs.  The Investor Partners paid all dealer manager commissions, discounts, and due diligence reimbursements and are allocated 100% of these costs.

(b) Represents a one-time fee paid to the Managing General Partner on the day the Partnership was funded equal to 1-1/2% of total investor subscriptions.

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

(d) The Managing General Partner receives monthly reimbursement from the Partnership for direct costs incurred by the Managing General Partner on behalf of the Partnership.

Allocations among Investor Partners; Deficit Capital Account Balances

PDC allocates the Investor Partners' share of revenues and costs of the Partnership among them in the same proportion as each Investor Partner's capital contribution bears to the aggregate of the capital contributions of all Investor Partners in the Partnership.

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To avoid the requirement of restoring a deficit capital account balance, there will be no allocations of losses to an Investor Partner to the extent those allocations would create or increase a deficit in his or her capital account (adjusted for liabilities, as provided in the limited partnership agreement).

Termination

Upon termination and final liquidation of the Partnership, PDC will distribute the assets of the Partnership to the partners based upon their capital account balances.  If PDC has a deficit in its capital account, PDC must restore the deficit; however, no Investor Partner will be obligated to restore his or her deficit, if any.

Amendment of Partnership Allocation Provisions

PDC is authorized to amend the limited partnership agreement, if, in its sole discretion based on advice from its legal counsel or accountants, an amendment to revise the cost and revenue allocations is required for those allocations to be recognized for federal income tax purposes because of either the promulgation of Treasury Regulations or other developments in the tax law.  Any new allocation provisions provided by an amendment must be made in a manner that would result in the most favorable aggregate consequences to the Investor Partners as nearly as possible consistent with the original allocations described in the limited partnership agreement.  See Section 11.09 of the limited partnership agreement.

Item 10 Recent Sales of Unregistered Securities

The Registrant was funded on August 31, 2007 upon completion of the private placement of its securities.  The offering was made solely to accredited investors, as that term is defined by Rule 501(a) under the Securities Act of 1933, and was effected in reliance upon §4(2) of the Securities Act and Rule 506 thereunder.  The Partnership sold for cash $89,402,885 of its securities in the offering.  The dealer-manager of the offering was PDC Securities Incorporated, a NASD-registered broker-dealer.  PDC Securities Incorporated is an affiliate of Petroleum Development Corporation, the Managing General Partner of the Partnership.  For additional information, see “Item 1, Business” and “Item 7, Certain Relationship and Related Transactions and Director Independence – Compensation to Managing General Partner and Affiliates.”

Item 11 Description of Registrant's Securities to be Registered

Units of Partnership Interest  In its offering, the Partnership sold units of general partnership interest and units of limited partnership interest in the partnership.  "Unit" means the partnership interest purchased by a limited partner or an additional general partner.  This interest is the right and obligation to share a proportional part of the Investor Partners' share of Partnership income, expense, assets and liabilities.  The fractional interest purchased by a one unit investment in the Investor Partners' interest in the Partnership is the ratio of one unit to the total number of units sold.  A general partner, excluding the Managing General Partner, referred to as “other general partners” will be able to apply tax deductions generated by the Partnership to reduce his/her federal adjusted gross income regardless of the source of the income, but he/she will have unlimited liability for the drilling and completion activities of the Partnership.  An individual investor who invested as a limited partner will be able to use his/her deductions to reduce taxable income only from passive sources.  The Internal Revenue Service defines passive income as income from partnership and rental activities.  One's liability as a limited partner is restricted to his/her investment in the Partnership.

Conversion of Units by the Managing General Partner and by Other General Partners  PDC will convert all units of other general partnership interest of the Partnership into the same dollar amount of units of limited partnership interest of the Partnership subsequent to the completion of drilling operations of the Partnership.  Prior to that time, other general partners may convert their units of additional general partnership interest into units of limited partnership interest if there is a material change in the amount of the Partnership's insurance coverage.  PDC must notify the other general partners if there is a material reduction of the insurance coverage, and those partners will be able to require PDC to convert their interests any time during the 30 days preceding the change.  Other general partners will not be able to convert their interest if the conversion would cause a termination of the Partnership for federal tax purposes.

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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.  The Managing General Partner is obligated to purchase, in any calendar year, Investor Partner units aggregating to 10% of the initial subscriptions if requested by the Investor Partners, subject to its financial ability to do so and opinions of counsel.  Repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis.

SUMMARY OF LIMITED PARTNERSHIP AGREEMENT

The limited partnership agreement in the form filed as an exhibit to this registration statement will govern all partners' rights and obligations.  The following statements concerning the limited partnership agreement are merely a summary of all the material terms of the limited partnership agreement, but do not purport to be complete and in no way amend or modify the limited partnership agreement.

Responsibility of Managing General Partner

The Managing General Partner shall have the exclusive management and control of all aspects of the business of the Partnership (see sections 5.01 and 6.01 of the limited partnership agreement).  No Investor Partner shall have any voice in the day-to-day business operations of the Partnership (see section 7.01 of the limited partnership agreement).  The Managing General Partner is authorized to delegate and subcontract its duties under the limited partnership agreement to others, including entities related to it (See section 5.02 of the limited partnership agreement).

Liability of General Partners, Including Additional General Partners

General partners, including additional general partners, have unlimited liability for Partnership activities.  The additional general partners are jointly and severally liable for all obligations and liabilities to creditors and claimants, whether arising out of contract or tort, in the conduct of Partnership operations (see section 7.12 of the limited partnership agreement).

PDC, as operator, maintains general liability insurance.  In addition, PDC has agreed to indemnify each additional general partner for the amounts of obligations, risks, losses, or judgments of the Partnership or the Managing General Partner which exceed the amount of applicable insurance coverage and amounts which would become available from the sale of all Partnership assets.  Such indemnification applies to casualty losses and to business losses, such as losses incurred in connection with the drilling of an unproductive well, to the extent such losses exceed the Additional General Partners’ interest in the undistributed net assets of the Partnership.  If, on the other hand, such excess obligations are the result of the negligence or misconduct of an Additional General Partner, or the contravention of the terms of the Partnership Agreement by the Additional General Partner, then the foregoing indemnification by the Managing General Partner would be unenforceable as to such Additional General Partner and such Additional General Partner would be liable to all other Partners for damages and obligations resulting therefrom.  (See section 7.02 of the limited partnership agreement).

The additional general partners, by execution of the limited partnership agreement, grant to the Managing General Partner the exclusive authority to manage the Partnership business in its sole discretion and to bind the Partnership and all partners in its conduct of the Partnership business.  The additional general partners may not participate in the management of the Partnership business; and the limited partnership agreement prohibits the additional general partners from acting in a manner harmful to the assets or the business of the Partnership or to do any other act which would make it impossible to carry on the ordinary business of the Partnership.  If an additional general partner acts contrary to the terms of the limited partnership agreement, losses caused by his or her actions will be borne by that additional general partner alone and that additional general partner may be liable to other partners for all damages resulting from his or her breach of the limited partnership agreement.  Section 7.01 Additional general partners who choose to assign their units in the future may do as only as provided in the limited partnership agreement.  Liability of partners who have assigned their units may continue after the assignment unless a formal assumption and release of liability is affected (see section 7.03 of the limited partnership agreement).

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Liability of Limited Partners

The West Virginia Uniform Limited Partnership Act governs the Partnership, under which law a limited partner's liability for the obligations of the Partnership is limited to his or her capital contribution, his or her share of Partnership assets and the return of any part of his or her capital contribution for a period of one year after the return (or six years in the event the return is in violation of the limited partnership agreement).  A limited partner will not otherwise be liable for the obligations of the Partnership unless, in addition to the exercise of his or her rights and powers as a limited partner, the person takes part in the control of the business of the Partnership (see section 7.01of the limited partnership agreement).

Allocations and Distributions

General  Profits and losses are to be allocated and cash is to be distributed in the manner described in “Item 7, Certain Relationships and Related Transactions, and Director Independence” and “Item 9, Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters," above (see Article III of the limited partnership agreement).

Time of Distributions  The Managing General Partner will determine and distribute not less frequently than quarterly cash available for distribution (see section 4.01 of the limited partnership agreement).  The Managing General Partner may, at its discretion, make distributions more frequently.  Notwithstanding any other provision of the limited partnership agreement to the contrary, no partner will receive any distribution to the extent the distribution will create or increase a deficit in that partner's capital account (as increased by his or her share of partnership minimum gain). (See section 4.03 of the limited partnership agreement).

Liquidating Distributions Liquidating distributions will be made in the same manner as regular distributions; however, in the event of dissolution of the Partnership, distributions will be made only after due provision has been made for, among other things, payment of all Partnership debts and liabilities. (See section 9.03 of the limited partnership agreement).

Voting Rights

Investor Partners owning 10% or more of the then outstanding units entitled to vote have the right to require the Managing General Partner to call a meeting of the partners (see section 7.07 of the limited partnership agreement).

Investor Partners may vote with respect to Partnership matters.  A majority in interest of the then outstanding units entitled to vote constitutes a quorum.  Each unit is entitled to one vote on all matters; each fractional unit is entitled to that fraction of one vote equal to the fractional interest in the unit.  Except as otherwise provided in the limited partnership agreement, at any meeting of Investor Partners, approval of any matters considered at the meeting requires the affirmative vote of a majority of units represented, in person or by proxy, at the meeting at which a quorum is present.  Approval of any of the following matters requires the affirmative vote of a majority of the then outstanding units entitled to vote, without the concurrence of the Managing General Partner:

· The sale of all or substantially all of the assets of the Partnership;

· The merger of the Partnership with another entity;

· Removal of the Managing General Partner and election of a new managing general partner;

· Dissolution of the Partnership;

· Any non-ministerial amendment to the limited partnership agreement;

· Cancellation of contracts for services with the Managing General Partner or affiliates; and

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· The appointment of a liquidating trustee in the event the Partnership is to be dissolved by reason of the retirement, dissolution, liquidation, bankruptcy, death, or adjudication of insanity or incapacity of the last remaining general partner.

Additionally, the Partnership is not permitted to participate in a roll-up transaction unless the roll-up has been approved by at least 66 2/3% in interest of Investor Partners (see sections 5.07(m) and 7.08 of the limited partnership agreement).

The Managing General Partner if it were removed by the Investor Partners may elect to retain its interest in the Partnership as a limited partner in the successor limited partnership (assuming that the Investor Partners determined to continue the Partnership and elected a successor Managing General Partner), in which case the former Managing General Partner would be entitled to vote its interest as a limited partner (see section 7.06 of the limited partnership agreement).

Investor Partners may review the Partnership's books and records and list of Investor Partners at any reasonable time and may copy the list of Investor Partners at their expense.  Investor Partners may submit proposals to the Managing General Partner for inclusion in the voting materials for the next meeting of Investor Partners for consideration by the Investor Partners.  With respect to the merger or consolidation of the Partnership or the sale of all or substantially all of the Partnership's assets, Investor Partners may exercise dissenter's rights for fair appraisal of their units in accordance with Section 31D-13-1302 of the West Virginia Business Corporation Act (see sections 7.07, 7.08, and 8.01 of the limited partnership agreement).

Retirement and Removal of the Managing General Partner

If the Managing General Partner desires to withdraw from the Partnership for whatever reason, it may do so only upon one hundred twenty (120) days prior written notice and with the written consent of the Investor Partners owning a majority of the then outstanding units (see section 6.03 of the limited partnership agreement).

If the Investor Partners desire to remove the Managing General Partner, they may do so at any time with the consent of the Investor Partners owning a majority of the then outstanding units, and upon the selection of a successor Managing General Partner by the Investor Partners owning a majority of the then outstanding units (see section 7.06 of the limited partnership agreement).

Term and Dissolution

The Partnership will continue for a maximum period ending December 31, 2057 unless earlier dissolved upon the occurrence of any of the following:

· the written consent of the Investor Partners owning a majority of the then outstanding units;

· the retirement, bankruptcy, adjudication of insanity or incapacity, withdrawal, removal, or death (or, in the case of a corporate Managing General Partner, the retirement, withdrawal, removal, dissolution, liquidation, or bankruptcy) of a Managing General Partner, unless a successor Managing General Partner is selected by the partners under the limited partnership agreement or the remaining Managing General Partner, if any, continues the Partnership's business;

· the sale, forfeiture, or abandonment of all or substantially all of the Partnership's property; or

· the occurrence of any event causing dissolution of the Partnership under the laws of the State of West Virginia (see section 9.01 of the limited partnership agreement).

Reports to Partners

The Managing General Partner will furnish to the Investor Partners of the Partnership semi-annual and annual reports which will contain financial statements (including a balance sheet and statements of income, partners' equity and cash flows), which statements at fiscal year end will be audited by an independent accounting firm.  Financial statements furnished in the Partnership's semi-annual reports will not be audited.  Semi-annually, all Investor Partners will also receive a summary itemization of the transactions between the Managing General Partner or any affiliate and the Partnership showing all items of compensation received by the Managing General Partner and its affiliates.  Annually beginning with the fiscal year ended December 31, 2007, oil and gas reserve estimates prepared by an independent petroleum engineer will also be furnished to the Investor Partners.  Annual reports will be provided to the Investor Partners within 120 days after the close of the Partnership fiscal year, and semi-annual reports will be provided within 75 days after the close of the first six months of the Partnership fiscal year.  In addition, the Investor Partners will receive on a monthly basis while the Partnership is participating in drilling and completion activities, reports containing a description of the Partnership's acquisition of interests in prospects, including farmins and farmouts, and the drilling, completion and abandonment of wells thereon.  All Investor Partners will receive a report containing information necessary for the preparation of their federal income tax returns and any required state income tax returns by March 15 of each calendar year.  Investor Partners will also receive in the monthly reports a summary of the status of wells drilled by the Partnership, the amount of oil or gas from each well and the drilling schedule for proposed wells, if known.  The Managing General Partner may provide other reports and financial statements as it deems necessary or desirable (see section 8.02 of the limited partnership agreement).

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Power of Attorney

Each partner has granted to the Managing General Partner a power of attorney to execute documents deemed by the Managing General Partner to be necessary or convenient to the partnership's business or required in connection with the qualification and continuance of the partnership (see section 10.01 of the limited partnership agreement).

Item 12 Indemnification of Directors and Officers

The Managing General Partner is entitled to reimbursement and indemnification for all expenditures made (including amounts paid in settlement of claims) or losses or judgments suffered by it in the ordinary and proper course of the Partnership's business, provided that the Managing General Partner has determined in good faith that the course of conduct which caused the loss or liability was in the best interests of the Partnership, that the Managing General Partner was acting on behalf of or performing services for the Partnership, and that the expenditures, losses or judgments were not the result of the negligence or misconduct on the part of the Managing General Partner (see section 6.04 of the limited partnership agreement).  The Managing General Partner has no liability to the Partnership or to any partner for any loss suffered by the Partnership which arises out of any action or inaction of the Managing General Partner if the Managing General Partner, in good faith, determined that the course of conduct was in the best interest of the Partnership and the course of conduct did not constitute negligence or misconduct of the Managing General Partner.  The Managing General Partner will be indemnified by the Partnership to the limit of the insurance proceeds and tangible net assets of the Partnership against any losses, judgments, liabilities, expenses and amounts paid in settlement of any claims sustained by it in connection with the Partnership, provided that the same were not the result of negligence or misconduct on the part of the Managing General Partner.

Notwithstanding the above, the Managing General Partner will not be indemnified for liabilities arising under federal and state securities laws unless

· there has been a successful adjudication on the merits of each count involving securities law violations; or

· the claims have been dismissed with prejudice on their merits by a court of competent jurisdiction; or

· a court of competent jurisdiction approves a settlement of the claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court considering the request for indemnification has been advised of the position of the Securities and Exchange Commission and of the position of any state securities regulatory authority in which securities of the Partnership were offered or sold as to indemnification for violations of securities laws;

· provided, however, the court need only be advised of the positions of the securities regulatory authorities of those states (a) which are specifically set forth in the Partnership's offering memorandum and (b) in which plaintiffs claim they were offered or sold Partnership units.

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In any claim for indemnification for federal or state securities laws violations, the party seeking indemnification must place before the court the position of the Securities and Exchange Commission, the Massachusetts Securities Division, and the Tennessee Securities Division or other respective state securities division with respect to the issue of indemnification for securities laws violations.

The Partnership will not incur the cost of the portion of any insurance which insures any party against any liability as to which the party is prohibited from being indemnified (see section 6.04 of the limited partnership agreement).

Item 13 Financial Statements and Supplementary Date

See index to Financial Statements on page F-1 herein.

Item 14 Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

Not applicable.

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Item 15  Financial Statements and Exhibits

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

(b) Exhibits. The following documents are filed as exhibits to this registration statement.

Certain confidential information in the various gas and oil purchase agreements listed in the Exhibit Index below has been omitted from the particular agreement.  The Partnership has filed a confidential treatment request with the Securities and Exchange Commission with respect to these omissions pursuant to Rule 24b-2 under the Securities Exchange Act of 1934.

Exhibit Ref. No.	Description
3.0	Limited Partnership Agreement (incorporated by reference to Exhibit 3.0 of the Partnership’s Form 10/A registration statement filed on August 6, 2008).
3.1	Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law (incorporated by reference to Exhibit 3.1 of the Partnership’s Form 10/A registration statement filed on August 6, 2008).
10.1	Assignment of leases to the Partnership (incorporated by reference to Exhibit 10.1 of the Partnership’s Form 10/A registration statement filed on August 6, 2008).
10.2	Drilling and operating agreement between PDC as Managing General Partner and the Partnership (incorporated by reference to Exhibit 10.2 of the Partnership’s Form 10/A registration statement filed on August 6, 2008).
10.3	Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999 (incorporated by reference to Exhibit 10.3 of the Partnership’s Form 10/A registration statement filed on August 6, 2008).
10.4	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982-A Limited and Creek Cattle Company, dated October 14, 1983 (incorporated by reference to Exhibit 10.4 of the Partnership’s Form 10/A registration statement filed on August 6, 2008).
10.5	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 (incorporated by reference to Exhibit 10.5 of the Partnership’s Form 10/A registration statement filed on August 6, 2008).
10.6	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 (incorporated by reference to Exhibit 10.6 of the Partnership’s Form 10/A registration statement filed on August 6, 2008).
10.7	Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and Petroleum Development Corporation, dated as of June 1, 2006 (incorporated by reference to Exhibit 10.7 of the Partnership’s Form 10/A registration statement filed on August 6, 2008).

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SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement 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

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

November 14, 2008

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/ Steven R. Williams	Director	November 14, 2008
Steven R. Williams	Petroleum Development Corporation,
	Managing General Partner of the Registrant
/s/ Richard W. McCullough	Chief Executive Officer	November 14, 2008
Richard W. McCullough	Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Darwin L. Stump	Chief Accounting Officer	November 14, 2008
Darwin L. Stump	Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(Principal accounting officer)
/s/ Jeffrey C. Swoveland	Director	November 14, 2008
Jeffrey C. Swoveland	Petroleum Development Corporation,
	Managing General Partner of the Registrant
/s/ Anthony J. Crisafio	Director	November 14, 2008
Anthony J. Crisafio	Petroleum Development Corporation,
	Managing General Partner of the Registrant
/s/ Joseph E. Casabona	Director	November 14, 2008
Joseph E. Casabona	Petroleum Development Corporation,
	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-2
Balance Sheets – as of March 31, 2008 (unaudited) and December 31, 2007	F-3
Statements of Operations – For the quarter ended March 31, 2008 (unaudited) and period from May 22, 2007 (Date of Inception) to December 31, 2007	F-4
Statements of Partners' Equity – For the quarter ended March 31, 2008 (unaudited) and period from May 22, 2007 (Date of Inception) to December 31, 2007	F-5
Statements of Cash Flows – For the quarter ended March 31, 2008 (unaudited) and period from May 22, 2007 (Date of Inception) to December 31, 2007	F-6
Notes to Financial Statements	F-7

F-1

Report of Independent Registered Public Accounting Firm

To the Partners of the Rockies Region 2007 Limited Partnership,

In our opinion, the accompanying balance sheet and the related statement of operations, partners' equity and cash flow present fairly, in all material respects, the financial position of Rockies Region 2007 Limited Partnership (the "Partnership") at December 31, 2007, and the results of its operations and its cash flows for the period May 22, 2007 (date of inception) to December 31, 2007 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 audit.  We conducted our audit 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 audit provides a reasonable basis for our opinion.

As discussed in Note 3 to the financial statements, the Partnership has significant related party transactions with Petroleum Development Corporation and its subsidiaries.

/s/PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

April 29, 2008

F-2

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Balance Sheets
Assets	(Unaudited) March 31, 2008			December 31, 2007
Current assets:
Cash and cash equivalents	$	1,324,340		$	783,845
Accounts receivable		6,241,293			1,160,201
Interest receivable		-			531,867
Oil inventory		13,176			-
Other assets		135,570			-
Total current assets		7,714,379			2,475,913
Oil and gas properties, successful efforts method		31,725,943			10,373,394
Wells in progress		46,128,727			40,286,695
Drilling advances to Managing General Partner		39,953,089			67,045,826
Oil and gas properties, at cost		117,807,759			117,705,915
Less accumulated depreciation, depletion and amortization		(1,776,733	)		(464,341	)
Oil and gas properties, net		116,031,026			117,241,574
Other assets-long term		371,491			-
Total Assets	$	124,116,896		$	119,717,487
Liabilities and Partners' Equity
Current liabilities:
Production taxes payable	$	520,487		$	87,479
Due to Managing General Partner-derivatives		4,877,368			319,365
Due to Managing General Partner-other		559,383			29,995
Total current liabilities		5,957,238			436,839
Due to Managing General Partner-Derivatives		2,092,857			-
Due to Managing General Partner-Other		371,491			-
Asset retirement obligations		160,113			55,643
Total liabilities		8,581,699			492,482
Partners' equity:
Managing General Partner		37,876,887			39,242,116
Limited Partners - 4,470 units issued and outstanding		77,658,310			79,982,889
Total Partners' equity		115,535,197			119,225,005
Total Liabilities and Partners' Equity	$	124,116,896		$	119,717,487

See accompanying notes to financial statements.

F-3

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Statements of Operations
	(Unaudited) Quarter Ended March 31, 2008			Period May 22, 2007 (date of inception) to December 31, 2007
Revenues:
Oil and gas sales	$	5,081,092		$	1,160,201
Oil and gas price risk management loss		(6,913,493	)		(319,365	)
Total revenues		(1,832,401	)		840,836
Operating costs and expenses:
Production and operating costs		541,676			121,897
Direct costs		38,899			-
Management fee		-			1,341,043
Depreciation, depletion and amortization		1,312,392			464,341
Accretion of asset retirement obligations		2,626			927
Total operating costs and expenses		1,895,593			1,928,208
Loss from operations		(3,727,994	)		(1,087,372	)
Interest income		38,186			1,320,134
Net (loss) income	$	(3,689,808	)	$	232,762
Net (loss) income  allocated to partners	$	(3,689,808	)	$	232,762
Less Managing General Partner's interest in net income or loss		1,365,229			(582,308	)
Net loss allocated to Investor Partners	$	(2,324,579	)	$	(349,546	)
Net loss per Investor Partner unit	$	(520	)	$	(78	)
Investor Partner units outstanding		4,470			4,470

See accompanying notes to financial statements.

F-4

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Statements of Partners' Equity
	Investor Partners			Managing General Partner			Total
Partners' contributions	$	89,402,885		$	38,659,808		$	128,062,693
Syndication costs		(9,070,450	)		-			(9,070,450	)
Net income (loss)		(349,546	)		582,308			232,762
Balance, December 31, 2007		79,982,889			39,242,116			119,225,005
Net loss (unaudited)		(2,324,579	)		(1,365,229	)		(3,689,808	)
Balance, March 31, 2008 (unaudited)	$	77,658,310		$	37,876,887		$	115,535,197

See accompanying notes to financial statements.

F-5

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Statements of Cash Flows
	(Unaudited) Quarter Ended March 31, 2008			Period May 22, 2007 (date of inception) to December 31, 2007
Cash flows from operating activities:
Net (loss) income	$	(3,689,808	)	$	232,762
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		1,312,392			464,341
Accretion of asset retirement obligations		2,626			927
Unrealized losses on derivative transactions		6,650,860			319,365
Changes in operating assets and liabilities:
Increase in accounts receivable		(5,081,092	)		(1,160,201	)
(Decrease) increase in interest receivable		531,867			(531,867	)
Increase in oil inventory		(13,176	)
Increase in due to Managing General Partner		393,818			29,995
Increase in production taxes payable		433,008			87,479
Net cash provided by (used in) operating activities		540,495			(557,199	)
Cash flows from investing activities:
Capital expenditures for oil and gas properties		-			(117,651,199	)
Net cash used in investing activities		-			(117,651,199	)
Cash flows from financing activities:
Investor Partners' contributions		-			89,402,885
Managing General Partner's contribution		-			38,659,808
Syndication costs paid		-			(9,070,450	)
Net cash provided by financing activities		-			118,992,243
Net increase in cash and cash equivalents		540,495			783,845
Cash and cash equivalents, beginning of period		783,845			-
Cash and cash equivalents, end of period	$	1,324,340		$	783,845
Supplemental disclosure of non-cash activity:
Asset retirement obligation, with corresponding increase to oil and gas properties	$	101,844		$	54,716

See accompanying notes to financial statements.

F-6

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

(1) Organization

The Rockies Region 2007 Limited Partnership (the “Partnership”) was organized as a limited partnership on May 22, 2007, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and gas properties and commenced business operations as of the date of organization.

Purchasers of partnership units subscribed to and fully paid for 38.5 units of limited partner interests and 4431.5 units of additional general partner interests at $20,000 per unit.  Petroleum Development Corporation has been designated the Managing General Partner of the Partnership and has a 37% ownership in the Partnership. Generally, throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 63% to the limited and additional general partners (collectively, the “Investor Partners”) are shared pro rata based upon the amount of their investment in the Partnership and 37% to the Managing General Partner.

Upon completion of the drilling phase of the Partnership's wells, all additional general partners units will be converted into units of limited partner interests and thereafter become limited partners of the Partnership.

In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.  The Partnership operates as a single business segment.

(2) Summary of Significant Accounting Policies

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.  The statements do not include any assets, liabilities, revenues or expenses attributable to any of the partners' other activities.

The interim financial statements as of March 31, 2008 have been prepared without audit in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission (“SEC”). Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. In our opinion, the interim financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly our financial position, results of operations and cash flows for the periods presented. The interim results of operations for the three months ended March 31, 2008, and the interim cash flows for the same interim period, are not necessarily indicative of the results to be expected for the full year or any other future period.

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 (FDIC) up to $100,000.  At times, the Partnership’s account balance may exceed FDIC limits.  The Partnership has not experienced losses in any such accounts and limits its exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Allowance for Doubtful Accounts

As of March 31, 2008 and December 31, 2007 the Partnership did not record an allowance for doubtful accounts.  The Partnership sells substantially all of its oil and gas to customers who purchase oil and gas from other Partnerships managed by the Partnership’s Managing General Partner.  Historically, none of the other Partnerships managed by the Partnership’s Managing General Partner have experienced significant losses on accounts receivable.  The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers.  The Partnership did not incur any losses on accounts receivable for the quarter ended March 31, 2008 or the year ended December 31, 2007.

Oil and Gas Properties

The Partnership accounts for its oil and gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and gas reserves.  Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves.  The Partnership obtains reserve reports from independent petroleum engineers annually as of December 31 of each year.  The Partnership adjusts for any major acquisitions, new drilling and divestures during the year as needed.  See “Note 9 – Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited)” to the financial statements for additional information regarding the Partnership’s reserve reporting. The Partnership does not maintain an inventory of undrilled leases.

Our estimates of proved reserves are based on quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. Annually, we engage independent petroleum engineers to prepare a reserve and economic evaluation of all our properties on a well-by-well basis as of December 31. Additionally, we adjust our oil and gas reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating oil and gas 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 our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income.

The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Cumulative costs on in-progress wells (“Suspended Well Costs”) remain capitalized until their productive status becomes known. If a final determination about the productive status of a well is unable to be made prior to issuance of the financial statements, the well is classified as Suspended Well Costs until there is sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. When a final determination of a well’s productive status is made, the well is removed from the suspended well status and the proper accounting treatment is recorded.

Upon sale or retirement of significant portions of or complete fields of depreciable or depletable property, the book value thereof, less proceeds, is credited or charged to income.  Upon sale of a partial unit of property, the proceeds are credited to property costs.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

The Partnership assesses impairment of capitalized costs of proved oil and gas properties each quarter 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 such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to the Partnership’s estimates of future production or product prices could result in an impairment of the Partnership's oil and gas properties in subsequent periods. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

Revenue Recognition

Sales of gas are recognized when gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.  Gas 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 contracts 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 gas and prevailing supply and demand conditions, so that the price of the gas fluctuates to remain competitive with other available gas supplies.  As a result, the Partnership’s revenues from the sale of gas will suffer if market prices decline and benefit if they increase.  However, the Managing General Partner may from time to time enter into derivative agreements, usually with a term of two years or less which may either fix or collar a price in order to reduce market price fluctuations. The Partnership believes that the pricing provisions of its gas contracts are customary in the industry.

The Partnership currently uses the “Net-Back” method of accounting for transportation arrangements of gas sales.  The Managing General Partner sells gas at the wellhead, collects a price, and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Managing General Partner’s customers and reflected in the wellhead price.

Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable.  The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers.  The Partnership does not refine any of its oil production.  The Partnership’s crude oil production is sold to purchasers 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.

For the quarter ended March 31, 2008, the Partnership sold oil and gas to three customers, Teppco Crude Oil, L.P., Williams Production RMT and DCP which accounted for 61%, 24% and 15%, respectively, of the Partnership’s oil and gas sales.

From August 31 to December 31, 2007 the Partnership sold oil and gas to two customers, Teppco Crude Oil, L.P., and DCP, which accounted for 87% and 13%, respectively, of the Partnership’s total oil and gas sales.

F-9

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Asset Retirement Obligations

The Partnership applies the provisions of SFAS 143, “Accounting for Asset Retirement Obligations” and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”, and accounts for asset retirement obligations by recording the fair value of its plugging and abandonment obligations when incurred, which is at the time the well is completely drilled.  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 asset retirement obligations are accreted, over the estimate life of the related asset, for the change in their present value.  The initial capitalized costs are depleted over the useful lives of the related assets, through charges to depreciation, depletion and amortization.  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 asset retirement obligations.  See “Note 8 – Asset Retirement Obligations” for a reconciliation of asset retirement obligation activity.

Derivative Financial Instruments

The Partnership accounts for derivative financial instruments in accordance with FAS Statement No. 133 "Accounting for Derivative Instruments and Certain Hedging Activities" as amended.  The Partnership's transactions in derivative instruments do not qualify for hedge accounting treatment under FAS No. 133.  Accordingly, the derivative instruments are recorded as an asset or liability on the balance sheet at fair value and the change in the fair value is recorded in oil and gas price risk management gain (loss), net on the statement of operations.  Because derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership, unrealized gains or losses are reported on the balance sheet as a net short-term or long-term receivable from or payable to the Managing General Partner.  The Partnership did not record any realized gains or losses on derivative contracts as of December 31, 2007, thus no amounts are due to/from the Managing General Partner on closed derivative positions at December 31, 2007.

PDC as Managing General Partner of the Partnership enters into derivative transactions including floors, ceilings, collars and fixed price swaps.  PDC enters into transactions on behalf of the Partnership in the same manner in which it enters into transactions for itself.  The Partnership participates in all hedging transactions entered into by the Managing General Partner in a given area after the partnership is formed. The transactions are on a production month basis; therefore a partnership may participate in a hedge for a future period before it has current production from that area.  As this partnership continues to drill and put wells into production, their share of the derivative positions will increase in future periods.  We believe that in this rapidly changing price environment, derivative positions are desirable to obtain more predictable results and to protect against possible severe price declines during this crucial stage of flush production from the Partnership wells.  This allocation methodology is considered reasonable by management and provides this result to the Partnership.

The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Managing General Partner seeks indicative price information from external sources including broker quotes and industry publications.

By using derivative financial instruments to manage exposures to changes in commodity prices, the Partnership exposes itself to credit risk.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Managing General Partner, which in turn owes the Partnership thus creating repayment risk.  The Managing General Partner minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

F-10

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Income Taxes

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

Use of Estimates

The Partnership has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of oil and gas reserves, future cash flows from oil and gas properties which are used in assessing impairment of long-lived assets, asset retirement obligations, and valuation of derivative instruments.

Recently Issued Accounting Standards

In December 2007, the FASB issued SFAS No. 160, Non-controlling Interests in Consolidated Financial Statement—An Amendments of ARB No. 51 ("SFAS No. 160").  SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity.  Additionally, SFAS No. 160 establishes reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.  SFAS No. 160 is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008.  The Partnership is evaluating the impact the provisions of SFAS No. 160 will have, if any, on its financial statements when adopted in 2009.

On March 19, 2008, the FASB issued FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities - an Amendment of FASB Statement 133 (SFAS No. 161). SFAS No. 161 enhances required disclosures regarding derivatives and hedging activities, including enhanced disclosures regarding how: (a) an entity uses derivative instruments; (b) derivative instruments and related hedged items are accounted for under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities; and (c) derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. Specifically, SFAS No. 161 requires:

· Disclosure of the objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation;

· Disclosure of the fair values of derivative instruments and their gains and losses in a tabular format;

· Disclosure of information about credit-risk-related contingent features; and

· Cross-reference from the derivative footnote to other footnotes in which derivative-related information is disclosed.

Statement 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  As SFAS No. 161 is disclosure related, the Partnership does not expect its adoption to have a material impact on the Partnership's financial statements.

In October 2008, the FASB issued FSP No. 157-3, Determining the Fair Value of a Financial Asset in a Market That Is Not Active, which applies to financial assets within the scope of accounting pronouncements that require or permit fair value measurements in accordance with SFAS No. 157.  The FSP clarifies the application of SFAS No. 157 in a market that is not active and defines additional key criteria in determining the fair value of a financial asset when the market for that financial asset is not active.  FSP FAS 157-3 was effective upon issuance and did not have a material impact on the Partnership’s financial statements.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Recently Implemented Accounting Standards

In June 2006, the Financial Accounting Standards Board ("FASB") issued Emerging Issues Task Force ("EITF") No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation).  EITF 06-3 addresses the income statement presentation of any tax collected from customers and remitted to a government authority and concludes that the presentation of taxes on either a gross basis or a net basis is an accounting policy decision that should be disclosed pursuant to Accounting Principles Board ("APB") No. 22, Disclosures of Accounting Policies.  For taxes that are reported on a gross basis (included in revenues and costs), EITF 06-3 requires disclosure of the amounts of those taxes in interim and annual financial statements, if those amounts are significant.  EITF 06-3 became effective for interim and annual reporting periods beginning after December 15, 2006.  The adoption of EITF 06-03, effective January 1, 2007, did not have a significant impact on the accompanying financial statements.  The Partnership's existing accounting policy, which was not changed upon the adoption of EITF 06-3, is to present taxes within the scope of EITF 06-3 on a net basis.

We adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 157, Fair Value Measurements, effective January 1, 2008.  SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 applies broadly to financial and nonfinancial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.  In February 2008, the Financial Accounting Standards Board ("FASB") issued FASB Staff Position “FSP”, No. 157-2, Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 by one year (to January 1, 2009) for non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  Nonfinancial assets and liabilities for which we have not applied the provisions of SFAS No. 157 include those initially measured at fair value, including our asset retirement obligations.  As of the adoption date, we have applied the provisions of SFAS No. 157 to our recurring measurements and the impact was not material to our underlying fair values and no amounts were recorded relative to the cumulative effect of a change in accounting.  We are currently evaluating the potential effect that the nonfinancial assets and liabilities provisions of SFAS No. 157 will have on our financial statements when adopted in 2009.  See Note 5 for further details on our fair value measurements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities.  SFAS No. 159 permits entities to choose to measure, at fair value, many financial instruments and certain other items that are not currently required to be measured at fair value.  The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions.  SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities.  The statement will be effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007.  As of March 31, 2008, we had not elected, nor do we intend, to measure additional financial asset and liabilities at fair value.

In April 2007, the FASB issued FSP FIN No. 39-1, Amendment of FASB Interpretation No. 39 ("FIN No. 39-1'), to amend certain portions of Interpretation 39.  FIN No. 39-1 replaces the terms "conditional contracts" and "exchange contracts" in Interpretation 39 with the term "derivative instruments" as defined in Statement 133.  FIN No. 39-1 also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments.  FIN No. 39-1 applies to fiscal years beginning after November 15, 2007, with early adoption permitted.  The January 1, 2008, adoption of FSP FIN 39-1 had no impact on our financial statements.

F-12

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

(3) Transactions with Managing General Partner and Affiliates

The Managing General Partner and its wholly-owned subsidiary, PDC Securities Incorporated, are reimbursed for certain Partnership operating expenses and receive fees for services as provided for in the Agreement.  As of March 31, 2008 and December 31, 2007 the Partnership owed the Managing General Partner $161,180 and $29,484, respectively, for operating costs.  As a result of derivative transactions executed by the Managing General Partner on behalf of the Partnership, at March 31, 2008 and December 31, 2007 there was also a  derivatives payable balance of $7,008,635 and $319,365, respectively, representing the unrealized derivative losses as of December 31, 2007.

The following table presents reimbursements and service fees paid by the Partnership to PDC or its affiliates as follows:

	(Unaudited) Quarter Ended March 31, 2008		Period May 22, 2007 (date of inception) through December 31, 2007
Drilling and completion costs (1)	$	-	$	117,651,199
Syndication costs (2)		-		9,070,450
Management fee (3)		-		1,341,043
Well operations fees		20,450		13,815
Transportation		41,150		-
Direct costs		38,899		-
Supplies and equipment		125,092		20,603

(1) Includes well costs of $44,942,605, drilling compensation of $5,662,768 and $67,045,826 of drilling advances to the Managing General Partner.

(2) The Partnership reimbursed PDC Securities Inc. a wholly owned subsidiary of the Managing General Partner, for dealer manager commissions, due diligence costs, marketing and support expenses and wholesaling fees as outlined in the Partnership Agreement.  Costs incurred by PDC between May 22 and August 31, 2007 relating to start-up and organization charges, for which no reimbursement was made, were insignificant.

(3) In accordance with the Partnership Agreement, a one-time management fee equal to 1½% of investors’ subscriptions was charged to the Partnership by the Managing General Partner.  This fee was paid by the Partnership to the Managing General Partner upon funding the Partnership.  The fee is treated as period costs in the year of formation and is non-refundable.

In addition, as the operator of the Partnership’s wells, the Managing General Partner receives all  proceeds from the sale of oil and gas produced and pays for all costs incurred related to services, equipment and supplies from vendors for all well production and operating costs and other direct costs for the Partnership.  Net revenue from oil and gas operations is distributed monthly to all partners based on their share of costs and revenues.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

The Managing General Partner’s capital contribution was made in two installments, a $20 million payment on August 31, 2007 with the remainder being paid on October 31, 2007 along with interest of $141,000 at 4.5 per cent.

The Partnership holds record title in its name to the working interest in each well.  PDC provides an assignment of working interest for the well bore prior to the spudding off the well and effective the date of the spudding of the well, to the Partnership in accordance with the Drilling and Operation Agreement.  Upon completion of the drilling of all of the Partnership wells, these assignments are recorded in the applicable county.  Partnership investors rely on PDC to use its best judgment to obtain appropriate title to these working interests.  Provisions of the limited partnership agreement relieve PDC from any error in judgment with respect to the waiver of title defects.  PDC takes those steps it deems necessary to assure that title to the leases is acceptable for purposes of the Partnership.  For additional information, see “Item 3, Properties – Title to Properties.”

(4) Derivative Financial Instruments

We account for derivative financial instruments in accordance with Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended.  Our derivative instruments do not qualify for use of hedge accounting under the provisions of SFAS No. 133.  Accordingly, we recognize all derivative instruments as either assets or liabilities on our  balance sheets at fair value.  Changes in the derivatives' fair values are recorded on a net basis in our statements of operations in oil and gas price risk management, net, for changes in derivative instruments related to our oil and gas sales and in sales from and cost of natural gas marketing activities for changes in derivative instruments related to our natural gas marketing activities.

We are exposed to the effect of market fluctuations in the prices of oil and natural gas as they relate to our oil and natural gas sales.  Price risk represents the potential risk of loss from adverse changes in the market price of oil and natural gas commodities.  We employ established policies and procedures to manage the risks associated with these market fluctuations using commodity derivatives.  Our policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

Risk Management Strategies.  Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas.  To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of March 31, 2008, our oil and natural gas derivative instruments were comprised of futures, swaps and collars.  These instruments generally consist of Colorado Interstate Gas Index ("CIG") -based contracts for Colorado production and NYMEX-based swaps and collars for our Colorado oil production.

· For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty.  The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

· Collars contain a fixed floor price (put) and ceiling price (call).  If the market price exceeds the call strike price or falls below the fixed put strike price, we receive the fixed price and pay the market price.  If the market price is between the call and the put strike price, no payments are due from either party.

We purchase puts and set collars and fixed-price swaps for our production to protect against price declines in future periods while retaining some of the benefits of price increases.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

While these derivatives are structured to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price changes in the physical market.  We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended although they are currently below market due to the continual rise in energy prices.

The following unaudited table summarizes our open derivative positions as of March 31, 2008.

Commodity	Type	Quantitiy Gas-MMbtu Oil-Barrels		Weighted Average Price		Total Contract Amount		Fair Value
Total Positions as of March 31, 2008
Natural Gas	Cash Settled Option Sales		2,768,395	$	9.30	$	25,734,457	$	(1,384,876	)
Natural Gas	Cash Settled Option Purchases		2,768,395		6.09		16,871,096		1,000,068
Natural Gas	Cash Settled Futures/Swaps Purchases		1,338,370		7.00		9,375,279		(2,082,062	)
Oil	Cash Settled Futures/Swaps Purchases		284,661		84.79		24,137,185		(3,442,013	)
Oil	Cash Settled Option Sales		177,609		102.63		18,227,124		(1,715,732	)
Oil	Cas Settled Option Purchases		177,609		70.00		12,432,630		654,390
								$	(6,970,225	)
Positions maturing in 12 months following March 31, 2008
Natural Gas	Cash Settled Option Sales		1,017,450		9.98		10,156,354		(840,126	)
Natural Gas	Cash Settled Option Purchases		1,017,450		6.69		6,803,163		177,621
Natural Gas	Cash Settled Futures/Swaps Purchases		1,338,370		7.00		9,375,279		(2,082,062	)
Oil	Cash Settled Futures/Swaps Purchases		150,846		84.48		12,742,838		(2,132,800	)
								$	(4,877,367	)

The maximum term for the derivative contracts listed above is 33 months.

The following table identifies the changes in the fair value of commodity based derivatives as reflected in the statements of operations:

	(Unaudited) Three months ended March 31, 2008			Period from May 22, 2007 to December 31, 2007
Oil and gas price risk management
Realized loss:
Oil	$	(262,633	)	$	0
Gas		0			0
Total realized loss		(262,633	)		0
Unrealized loss		(6,650,860	)		(319,365	)
Oil and gas price risk management loss, net	$	(6,913,493	)	$	(319,365	)

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

(5) Fair Value Measurements

As described above in Note 2, in September 2006, the FASB issued SFAS No. 157, Fair Value Measurements.  We adopted the provisions of SFAS No. 157 effective January 1, 2008.

Valuation hierarchy.  SFAS No. 157 establishes a fair value hierarchy that requires an entity 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.  The three levels of inputs that may be used to measure fair value are defined as:

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

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

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.  Instruments included in Level 3 consist of our commodity derivatives for CIG based natural gas swaps, oil swaps, and oil and natural gas options.

Determination of fair value.  We measure fair value based upon quoted market prices, where available.  Our 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.  Our valuation determination also gives consideration to our nonperformance risk on our own liabilities as well as the credit standing of our counterparties.  The Managing General Partner has evaluated the credit risk of their receivables including the portion allocated to the Partnership for the counterparties using credit default swap values for each counterparty with the outstanding hedge positions for the appropriate time period to calculate the maximum exposure.  The Managing General Partner evaluated their exposure and determined that it was immaterial for itself and the Partnership.  Furthermore, while we believe 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.

SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy and requires a separate reconciliation of fair value measurements categorized as Level 3.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

The following unaudited table presents, for each hierarchy level our assets and liabilities including both current and non-current portions, measured at fair value on a recurring basis as of March 31, 2008:

	Level 1		Level 2		Level 3			Total
Assets:
Commodity based derivatives	$	-	$	-	$	-		$	-
Liabilities:
Commodity based derivatives		-		-		(6,970,225	)		(6,970,225	)
Net fair value of commodity based derivatives	$	-	$	-	$	(6,970,225	)	$	(6,970,225	)

The following table sets forth a reconciliation of our Level 3 fair value measurements:

	(Unaudited) Net Level 3 Derivatives
Balance at January 1, 2008	$	(319,365	)
Realized and unrealized losses		(6,913,493	)
Purchases, sales, issuances and settlements, net		262,633
Balance at March 31, 2008 (unaudited)	$	(6,970,225	)

(6) Partners’ Equity and Cash Distributions

Partners’ Equity

A unit represents the individual interest of an 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, Investor Partners may request that the Managing General Partner repurchase units pursuant to the repurchase program.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Allocation of Partners’ Interest

The table below summarizes the participation of the Investor Partners and the Managing General Partner in the revenues and costs of the Partnership, taking into account the Managing General Partner's capital contribution, which was equal to 43.24% of the Investor Partners’ initial capital.

	Investor Partners			Managing General Partner
Partnership Revenue:
Oil and gas sales		63	%		37	%
Oil and gas price risk management gain (loss)		63	%		37	%
Sale of productive properties		63	%		37	%
Sale of equipment		63	%		37	%
Sale of undeveloped leases		63	%		37	%
Interest income		63	%		37	%
Partnership Costs:
Organization costs (a)		0	%		100	%
Broker-dealer commissions and expenses/syndication costs (a)		100	%		0	%
Cost of oil and gas properties:
Undeveloped lease costs		0	%		100	%
Tangible well costs		0	%		100	%
Intangible drilling costs		100	%		0	%
Managing General Partner's drilling compensation		100	%		0	%
Direct drilling and compensation costs, excluding
Managing General Partner’s drilling compensation		63	%		37	%
Other costs and expenses:
Management fee (b)		100	%		0	%
Production and operating costs (c)		63	%		37	%
Depreciation, depletion and amortization expense		63	%		37	%
Accretion of asset retirement obligations		63	%		37	%
Direct costs (d)		63	%		37	%

(a) The Managing General Partner paid all legal, accounting, printing, and filing fees associated with the organization of the Partnership and the offering of units and is allocated 100% of these costs.  The Investor Partners paid all dealer manager commissions, discounts, and due diligence reimbursements and are allocated 100% of these costs.

(b) Represents a one-time fee paid to the Managing General Partner on the day the Partnership was funded equal to 1-1/2% of total investor subscriptions.

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

(d) The Managing General Partner receives monthly reimbursement from the Partnership for direct costs incurred by the Managing General Partner on behalf of the Partnership.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

The following table presents the allocation of net income to the Investor Partners and the Managing General Partner for each of the periods presented.

	(Unaudited) Quarter Ended March 31, 2008			Period May 22, 2007 (date of inception) to December 31, 2007
Allocation of Partners' Interest in Net income (loss):
Net income (loss) allacable to the partners	$	(3,689,808	)	$	232,762
Plus Management fee		-			1,341,043
Adjusted net income (loss) allacable to the partners	$	(3,689,808	)	$	1,573,805
Net loss allacable to Investor Partners:
63% of Adjusted net income (loss) allacable to the partners	$	(2,324,579	)	$	991,497
100% of Management fee		-			(1,341,043	)
Net loss allacable to Investor Partners		(2,324,579	)		(349,546	)
Net (income) loss allacable to Managing General Partner:
37% of adjusted net income (loss) allocable to the partners		(1,365,229	)		582,308
Net income (loss) allocable to Managing General Partner		(1,365,229	)		582,308
Net income (loss) allocable to the partners	$	(3,689,808	)	$	232,762

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.  The Managing General Partner is obligated to purchase, in any calendar year, Investor Partner units aggregating to 10% of the initial subscriptions if requested by the Investor Partners, subject to its financial ability to do so and opinions of counsel.  Repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis.

Cash Distributions

The limited partnership agreement requires the Managing General Partner to distribute cash available for distribution not less frequently than quarterly.  The Managing General Partner will determine and distribute, if funds are available for distribution, cash on a monthly basis.  The Managing General Partner will make cash distributions of 63% to the Investor Partners and 37% to the Managing General Partner throughout the term of the Partnership.  The Partnership’s first cash distribution was paid on May 27, 2008, $1,016,684, or $227.44 per unit, to its Investor Partners and $597,100 to its Managing General Partner for a total cash distribution of $1,613.784.

(7) Costs Relating to Oil and Gas Activities

The Partnership is engaged solely in oil and gas activities, all of which are located in the continental United States.  Drilling operations began upon funding on August 31, 2007 with payments made for all planned drilling and completion costs for the Partnership made in December 2007.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Costs capitalized for these activities are as follows:

	(Unaudited) March 31, 2008		December 31, 2007
Leasehold costs	$	1,042,746	$	438,183
Development costs		30,683,197		9,935,211
Oil and gas properties, successful efforts method		31,725,943		10,373,394
Wells in progress		46,128,727		40,286,695
Drilling advances to Managing General Partner		39,953,089		67,045,826
Oil and gas properties at cost	$	117,807,759	$	117,705,915

Wells in progress represents expenditures incurred for wells on which drilling and/or completion activities have commenced but has not been completed.  Drilling advances to Managing General Partner represent prepayments to the Managing General Partner for the development of oil and gas properties on which drilling has not commenced.

(8) Asset Retirement Obligations

Changes in carrying amount of asset retirement obligations associated with oil and gas properties are as follows:

	(Unaudited) Quarter Ended March 31, 2008		Period May 22, 2007 (date of inception) through December 31, 2007
Balance at beginning of period	$	55,643	$	-
Obligations assumed with development activities		101,844		54,716
Accretion expense		2,626		927
Balance at end of period	$	160,113	$	55,643

The discount rate used in calculating the asset retirement obligation and related accretion at March 31, 2008 and December 31, 2007 was 6.61% and 6.78%, respectively, which approximates the borrowing rate of the Managing General Partner for the quarter in which the retirement obligation was recorded.

(9) Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited)

The tables below set forth information as of March 31, 2008 and December 31, 2007 regarding our estimated proved reserves. Reserves cannot be measured exactly, because reserve estimates involve subjective judgment.  The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes.  The Partnership utilized its internal petroleum engineering department for the March 31, 2008 reserve report and utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. for its 2007 reserve report.  The independent engineer’s estimates are made using available geological and reservoir data as well as production performance data. The estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance. 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, oil and gas production, well test data, historical costs of operations and developments, product prices, or any agreements relating to current and future operations of properties and sales of production.  The Partnership's independent reserve estimates are reviewed and approved by the Managing General Partner's internal engineering staff and management.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Proved reserves are the estimated quantities of oil and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  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.

Proved developed reserves are the quantities of oil and natural gas expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion.  In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities.

Neither the present value of estimated future net cash flows nor the standardized measure is intended to represent the current market value of the estimated oil and gas reserves we own.  An analysis of the change in estimated quantities of proved oil and gas reserves is shown below:

	Oil (Bbls)
	March 31, 2008			December 31, 2007
Proved reserves:
Beginning of year		361,100			-
Revisions of previous estimates		-			-
New discoveries, extensions and other additions		693,500			374,300
Production		(36,900	)		(13,200	)
End of Period		1,017,700			361,100

	Gas (Mcfs)
	March 31, 2008			December 31, 2007
Proved reserves:
Beginning of year		1,207,200			-
Revisions of previous estimates		-			-
New discoveries, extensions and other additions		7,883,300			1,231,500
Production		(280,300	)		(24,300	)
End of Period		8,810,200			1,207,200

	Natural gas		Oil
	(Mcf)		(Bbls)
Proved Developed Reserves, as of:
December 31, 2007		599,714		191,281
March 31, 2008		7,325,583		645,221

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Summarized in the following table is information with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves.  Future cash inflows are computed by applying year-end prices of oil and gas relating to our proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future development costs include the development costs related to recompletions of wells drilled in the Codell formation, as described in “Item 1, Business, Drilling Activities.”

	March 31, 2008			December 31, 2007
Future estimated cash flows	$	162,197,300		$	38,136,800
Future estimated production costs		(26,342,800	)		(6,113,700	)
Future estimated development costs		(6,346,100	)		(2,505,900	)
Future net cash flows		129,508,400			29,517,200
10% annual discount for estimated timing of cash flows		(60,854,000	)		(14,741,500	)
Standardized measure of discounted future estimated net cash flows	$	68,654,400		$	14,775,700

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows for the quarter ended March 31, 2008 and the  period from May 22, 2007 (date of inception) to December 31, 2007:

	March 31, 2008			December 31, 2007
Sales of oil and gas production, net of production costs	$	(4,480,000	)	$	(1,038,300	)
Net changes in prices and production costs		(533,000	)		521,000
Extensions, discoveries, and improved recovery,less related costs		55,915,000			14,776,000
Development cost incurred during the period		-			-
Revisions of previous quantity estimates		-			-
Accretion of discount		525,000			-
Timing and other		2,451,700			517,000
Net change	$	53,878,700		$	14,775,700

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions.  Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions.  The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.  Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

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ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

(10) Commitments and Contingencies

Royalty Litigation.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 Partnership’s Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on gas produced from wells operated by the Managing General Partner in 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 in June 2007. A second similar Colorado class action suit was filed against the Managing General Partner in the U.S. District Court for the District of Colorado on December 2007 by Ted Amsbaugh, et al.  In 2008, the Court granted the plaintiff’s motion to consolidate the action with the Droegemueller Action.

Based on the mediation held in May 2008, and subsequent negotiations, $34,153 had previously been accrued by the Partnership for this litigation for the period ended June 30, 2008, which represented the expected settlement related to all periods through June 30, 2008.  On October 10, 2008 the court issued preliminary approval of the settlement agreement.  Although the Partnership was not named as a party in the suit, the lawsuit states that it relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s 75 wells in the Wattenberg field subject to the settlement.  The portion of the proposed settlement related to the Partnership’s wells through all periods prior to September 30, 2008 is $59,825.  During the third quarter of 2008, an additional amount of $25,672 plus legal costs of $3,022 was recorded to fully accrue for the settlement which the Managing General Partner expects to pay into an escrow account for the Partnership in the fourth quarter of 2008.  Final approval and distribution is expected around March 1, 2009.  These amounts will be deducted from future Partnership distributions.

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