Rockies Region 2006 Limited Partnership 10K 2007 Annual report

		Page
	PART I
Item 1	Business	1
Item 1A	Risk Factors	7
Item 1B	Unresolved Staff Comments	14
Item 2	Properties	14
Item 3	Legal Proceedings	15
Item 4	Submissions of Matters to a Vote of Security Holders	16

	PART II
Item 5	Market Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6	Selected Financial Data	17
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	24
Item 8	Financial Statements and Supplementary Data	26
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	26
Item 9A	Controls and Procedures	26
Item 9B	Other Information	28

	PART III
Item 10	Directors, Executive Officers and Corporate Governance	28
Item 11	Executive Compensation	31
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	31
Item 13	Certain Relationships and Related Transactions, and Director Independence	31
Item 14	Principal Accountant Fees and Services	34

	PART IV
Item 15	Exhibits, Financial Statement Schedules	35

Signatures		36

Financial Statements		F-1

PART I

Item 1. Business.

General

Rockies Region 2006 Limited Partnership (the "Partnership" or the "Registrant") was organized as a limited partnership on July 20, 2006, under the West Virginia Uniform Limited Partnership Act. Upon completion of a private placement of its securities on September 7, 2006, the Partnership was funded and commenced its business operations. The Partnership was funded with initial contributions of $89,940,527 from 2,022 limited and general partners, excluding the managing general partner (collectively, the “Investor Partners”) and a cash contribution of $38,912,342 from Petroleum Development Corporation (“PDC”), the Managing General Partner. After payment of syndication costs of $9,084,039 and a one-time management fee to the Managing General Partner of $1,349,108, the Partnership had available cash of $118,419,722 to commence Partnership activities. The Partnership owns natural gas and oil wells located in Colorado and North Dakota, and from the wells, it produces and sells natural gas and oil.

Drilling Activities

As of December 31, 2007, the Partnership has conducted the following drilling activities:


		Colorado	North Dakota
Development wells: (a)
	Drilled, completed and producing	86	4
	Dry holes	1	-
Exploratory wells: (b)
	Drilled , completed and producing	-	1
	Dry holes	3	2
Total Wells Drilled		90	7

a.	A development well is a well that is drilled close to and into the same formation as a well which has already produced and sold oil or natural gas.

b.	An exploratory well is one which is drilled in an area where there has been no oil or natural gas production, or a well which is drilled to a previously untested or non-producing zone in an area where there are wells producing from other formations.

The ninety-seven wells in the table above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been utilized.

Since the Partnership has completed drilling as of December 31, 2007, and the ninety-one wells noted above are producing oil and/or natural gas, the Partnership’s business plan going forward is to produce and sell the oil and natural gas from the Partnership’s wells, and to make distributions to the partners as outlined in the Partnership’s cash distribution policy in “Item 5, Market for the Registrant's Common Equity and Related Stockholder Matters.”

The address and telephone number of the Partnership and Petroleum Development Corporation ("PDC"), the Managing General Partner of the Partnership, are 120 Genesis Boulevard, Bridgeport, West Virginia 26330 and (304) 842-6256.

Plan of Operations

The Partnership has invested in the drilling of ninety-seven prospects on which it has drilled an equal number of wells. The Partnership’s working interest in these wells is generally 99.9%, except for a few wells in which the Partnership’s working interest ranges from 63.49% to 100%. As indicated by the table above, ninety-one wells are producing.

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The Partnership drilled sixty-four of its Colorado wells to the Codell formation in the Wattenberg Field, Colorado, of which one well was determined to be a developmental dry hole and sixty-three wells have been successfully completed and are in production. The Partnership 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 increase the production rate and recoverable reserves of the wells. On average, the production resulting from PDC's Codell recompletions has been profitable; 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 approximately $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.

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.

PDC, in some cases, provides equipment and supplies, and performs salt water disposal services and other services for the Partnership. PDC sold 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 in Colorado and North Dakota are in the vicinity of transmission pipelines and gathering systems. PDC believes there are sufficient transmission pipelines and gathering systems for the Partnership's natural gas production, subject to some seasonal curtailment. 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 natural 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 natural 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 natural 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 natural gas 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.

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Price Hedging. The Partnership utilizes commodity based derivative instruments to manage a portion of the exposure to price volatility stemming from oil and natural gas sales. These instruments consist of Colorado Interstate Gas Index (“CIG”)-based contracts for Colorado natural gas production and NYMEX-traded oil futures and option contracts for Colorado and North Dakota oil production. The contracts provide price protection for committed and anticipated oil and natural gas purchases and sales, generally forecasted to occur within the next one- to two-year period. The Partnership's policies prohibit the use of oil and natural 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 realized for the sale of natural 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, net."

The Partnership is subject to price fluctuations for natural 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. The Partnership manages price risk on only a portion of its anticipated production, so the remaining portion of its production is subject to the full fluctuation of market pricing.

Drilling and Operating Agreement. The Partnership has entered into a drilling and operating 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 are 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 then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies.

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 the operator 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 natural 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.

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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.

Competition and Markets

Competition is high among persons and companies involved in the exploration for and production of oil and natural 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 natural gas companies in the United States. The national supply of natural gas is widely diversified. As a result of this competition and FERC and Congressional deregulation of natural gas and oil prices, prices are generally determined by competitive forces.

The marketing of any oil and natural 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 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 natural 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 natural gas industry by requiring pipelines to separate their storage, sales and transportation functions and establishing an industry-wide structure for "open-access" transportation service. 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 natural gas production in order to meet projected increases in natural 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 U.S., where natural gas is the preferred fuel for environmental reasons, and electric power demand has directly affected demand for natural gas.

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 natural gas production. Legislation that Congress may consider with respect to oil and natural 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 natural gas produced and sold from the Partnership's wells.

Various parts of the fields the Partnership’s wells are in are crossed by pipelines belonging to Colorado Interstate Gas, Encana, Duke, Williams and others. These companies have all traditionally purchased substantial portions of their supply from Colorado producers. Transportation on these systems requires that delivered natural gas meet quality standards and that a tariff be paid for quantities transported.

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Sales of natural gas from the Partnership's wells to Duke Energy, Williams and Bear Paw Energy 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 natural gas directly from natural 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 and attaching gas supply and has added to competition in the natural gas marketplace.

Natural Gas and Crude Oil Pricing

PDC sells the natural gas and oil from Partnership wells in Colorado and North Dakota subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of PDC and the Partnership. Currently, PDC sells Partnership natural gas in the Piceance Basin primarily to Williams Production RMT, which has an extensive gathering and transportation system in the field. In the Wattenberg Field, the natural gas is sold primarily to DCP Midstream, LP, 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 by capacity interruptions on pipelines transporting gas out of the region.

Currently, PDC sells crude oil from Partnership wells primarily to Teppco Crude Oil, L.P and Suncor Energy Marketing, Inc. 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 natural gas are set by the market, other aspects of the Partnership's business and the oil and natural gas industry in general are heavily regulated. The availability of a ready market for oil and natural 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 natural 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 natural gas, to prevent waste of oil and natural gas, to protect rights to 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. We believe that the Partnership 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 natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Partnership's operations may be subject.

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 natural gas industry in general, our business and prospects could be adversely affected.

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We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The U.S. Environmental Protection Agency, or EPA, and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our 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 might affect the petroleum and natural gas industries occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. These proposals involve, among other things, imposition of direct or indirect price limitations on natural gas production, expansion of drilling opportunities in areas that would compete with Partnership production, imposition of land use controls, landowners' "rights" legislation, alternative fuel use requirements and/or tax incentives and other measures. The petroleum and natural gas industries historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. We cannot determine to what extent our 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 us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our pipeline, gathering and transportation operations are subject to the many hazards inherent in the natural 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 natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain 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 our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or whether insurance will be available at all. Furthermore, we are not insured against our 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 our inability to deliver gas.

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.

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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 the Managing General Partner and the Partnership are co-insured and co-beneficiaries with respect to the insurance coverage referred to in #2 and #5 below. 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.

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

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

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

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

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 million, but in no event less than $10 million during drilling operations.

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 Natural Gas and Oil Investments

The oil and natural gas business is speculative and may be unprofitable and result in the total loss of investment. Although, the drilling and completion operations undertaken by the Partnership for the development of oil and natural gas reserves have been completed, the oil and natural 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 natural gas in sufficient quantities or quality to return a profit on the amounts expended. The prices of oil and natural gas play a major role in the profitability of the Partnership. Partnership wells may not produce sufficient natural 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.

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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 might 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. If the Partnership requires additional capital in the future, it 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 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 natural 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 natural gas prices is increased.

Reductions in prices of oil and natural 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 natural gas and oil prices. The prices for domestic natural 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 natural 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 natural gas and/or oil prices would result in lower revenues for the Partnership and a reduction of cash distributions to the partners of the Partnership. Further, reductions in prices of oil and natural gas may result in shut-ins thereby resulting in lower production, revenues and cash distributions. For instance, due to the downward trend of Colorado natural gas selling prices in the third quarter 2007, the Managing General Partner decided to shut-in 11 of the Partnership’s wells located in the Piceance Basin for a period of approximately four weeks, beginning on October 1, 2007. As the Colorado selling prices for natural gas began to rise during the month of October, the Managing General Partner restarted production in phases between November 1, 2007 and November 5, 2007 for all 11 of the wells that were shut-in. While the duration of this shut-in did not have a significant impact, longer shut-in durations could result in significant reductions in production, revenues and cash distributions.

The high level of drilling activity could result in an oversupply of natural 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 natural gas market has been characterized by excess demand compared to the supplies available, leading in general to higher prices for natural gas. The high level of drilling, combined with a reduction in demand resulting from higher prices, could result in an oversupply of natural 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 natural gas the Partnership produces, reduced profitability for the Partnership and reduced cash distributions to the Investor Partners. In the third and fourth quarter of 2007, the price of natural 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 arose prior to conversion to limited partners, which occurred on August 30, 2007. 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.

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Through their involvement in 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's being less profitable and a reduction in cash distributions to the investors. PDC's continued active participation in oil and natural 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. 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's 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 our natural gas and oil production to achieve a more predictable cash flow and to reduce exposure to adverse fluctuations in the prices of natural 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 natural 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 income statements, and our net income is subject to greater volatility than if our derivative instruments qualified for hedge accounting. The market prices for oil and natural gas, 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 our 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 investors. The sale of any natural 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 natural 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 natural gas or oil production, or to reduce the amount of natural 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 partners of the Partnership.

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 natural 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 natural gas and/or oil we 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 natural 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 natural 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 investors. 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 partnership natural gas or oil production could reduce the Partnership's profitability and a reduction in cash distributions to the investors. Drilling wells in areas remote from marketing facilities may delay production from those wells until sufficient reserves are established to justify construction of necessary pipelines and production facilities. 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 natural 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, oil and gas 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 generally based on prices and costs as of the date of the estimate. 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 production activities in some of the areas of operation. Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions. In certain areas, drilling and other oil and natural 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 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 natural 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 pursue mediation of the matter.

Many of the subject properties include working interests owned by partnerships of which PDC is the managing general partner, including the working interests of the Partnership. Although at this time the Partnership has not been named as a party in these suits, the Managing General Partner believes that the majority of the Partnership’s 64 wells in the Wattenberg field will be subject to the lawsuit. The lawsuit seeks unspecified damages. PDC has retained Colorado counsel to defend the interest of PDC and its sponsored partnerships in this matter. PDC disputes the plaintiffs' claims and intends to defend the lawsuit vigorously. While PDC presently believes that the ultimate outcome of these proceedings will not materially harm PDC's and the various partnerships' respective financial position, cash flows, or overall results of operations, litigation is subject to inherent uncertainties, and unfavorable rulings could occur. An unfavorable ruling could include money damages. Were an unfavorable ruling to occur, the Court could determine that the royalty owners have a right to a greater share of the revenues from PDC's and the Partnership's respective wells than they have been receiving, including past revenues. The Court could rule that PDC and the Partnership owe the royalty owners revenues for previous production plus interest and could require both PDC and the Partnership to pay royalty owners unreduced royalties on future production, the result of which could reduce PDC's and the Partnership's future revenues.

Were such a ruling to be rendered, the Partnership might be liable for additional royalties not paid to the owners from the time that the Partnership first produced natural gas from its wells until final judgment by the Court. Moreover, the Partnership might be required to pay additional royalties to the owners for natural gas production in the future following the Court's final judgment, and incur legal fees. Therefore, under these circumstances, it is likely that the profitability of the Partnership would be reduced and that future cash distributions to the investors in the Partnership likewise would be reduced.

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 therefrom 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.

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Dry hole costs and impairment charges associated with the Partnership's drilling have resulted in reduced distributions to the investors. To date, the Partnership has drilled a total of 97 wells. Of these wells, six have been determined to be commercially unproductive and therefore declared to be dry holes. As dry holes result in no production of oil and natural gas, the occurrence of dry holes causes the revenues and distributions to be less than if the wells drilled had been commercially productive. As of December 31, 2007, the Partnership recorded $8,132,943 in exploratory dry hole costs.

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. From inception through December 31, 2007, the Partnership's impairment charges totaled $9,575,300. Unlike dry holes, impaired properties may still produce oil and natural 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.

The general partners, including the Managing General Partner, are individually liable for Partnership obligations and liabilities that arose prior to conversion to limited partners (which occurred after the drilling completion operations were finished on August 30, 2007) 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 were converted into units of limited partner interests and thereafter became 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.

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A substantial part of our natural 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 natural 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, natural gas prices in the Rocky Mountain Region fell disproportionately when compared to other markets, due in part to continuing constraints in transporting natural 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. The implementation is based on a phased approach, with the financial reporting system to be implemented in the first quarter of 2008. 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.

The Managing General Partner and various limited partnership 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 have not filed their amended annual reports for the years ended prior to and including December 31, 2004 or their amended reports for the quarter ended March 31, 2005, and have not yet filed their quarterly reports for the quarters ended June 30 and September 30, 2005 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, June 30 and September 30, 2007. 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.

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. 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. See “Item 9A – Controls and Procedures” for further discussion of the Managing General Partner’s internal control over financial reporting.

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Item 1B. Unresolved Staff Comments

None

Item 2. Properties

The Partnership’s properties consist of working interests in natural gas wells and the ownership in leasehold acreage in the spacing units for the ninety-seven 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 September 7, 2006, and as of December 31, 2006, sixty-nine wells were in progress. As of December 31, 2007 a total of ninety-seven gross wells had been drilled and the status as of that date is reflected in the table below. The Partnership’s ninety-one gross producing wells were drilled in Colorado and North Dakota.

		Gross Wells	Net Wells
Development wells:
	Drilled, completed and producing	90	89.07
	Dry holes	1	1.00
Exploratory wells:
	Drilled, completed and producing	1	.64
	Dry holes	5	5.00
Total Wells Drilled		97	95.71

The ninety-seven wells in the table above are the only wells to be drilled by the Partnership since the all of the funds raised in the Partnership offering have been utilized.

Productive wells consist of producing wells and wells capable of producing oil and gas in commercial quantities, including gas wells awaiting pipeline connections to commence deliveries. Gross wells refers to the number of wells in which the Partnership has an interest. Net wells refers to gross wells multiplied by the percentage working interest owned by the Partnership.

The Partnership has eighty-seven development wells and three exploratory wells in Colorado and four development wells and three exploratory wells in North Dakota. Of the wells in Colorado, sixty-four of the developmental wells and the three exploratory wells are located in the Wattenberg Field (DJ Basin) and twenty-three are located in the Grand Valley Field (Piceance Basin). Four of the wells drilled in the Wattenberg Field were determined to be dry holes. The details of these prospect areas are further outlined below.

Colorado. Wattenberg Field, located north and east of Denver, Colorado, is in the Denver-Julesburg (DJ) Basin. The typical well production profile has an initial high production rate and relatively rapid decline, followed by years of relatively shallow decline. Natural 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. 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 is the Codell sand which produces a combination of natural gas and oil.

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The Grand Valley Field is in the Piceance Basin, located near the western border of Colorado. Wells in the Piceance Basin generally produce natural gas along with small quantities of oil and water. 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.

North Dakota. The Partnership drilled wells in the western portion of the Williston Basin, located in northwestern North Dakota. The Partnership's one successful well drilled in this area produces oil and natural gas, with some associated produced water. Wells drilled in this area target hydrocarbon reserves in the Nesson and/or Bakken interval.

Oil and Gas Reserves

All of the Partnership’s natural gas and oil reserves are located in the United States. The Partnership 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 natural 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. See “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)” to the financial statements for additional information regarding the Partnership’s reserves.

Title to Properties

The Partnership holds record title in its name to leases. PDC has assigned its interest in the leases to the Partnership. Partnership investors rely on PDC to use its best judgment to obtain appropriate title to leases. 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. The leases, having been assigned to the Partnership, are not subject to claims by creditors of PDC.

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 natural 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.

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 3. 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. PDC has been named as defendant in two class action lawsuits, which were consolidated in January 2008. Although at this time the Partnership has not been named as a party in this suit, the Managing General Partner believes that a majority of the Partnership's 64 wells in the Wattenberg field will be subject to the lawsuit. See “Note 8 – Commitments and Contingencies” in the Notes to the Financial Statements for additional information related to this litigation.

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Item 4. Submission of Matters to a Vote of Security Holders

None

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

At December 31, 2007, the Partnership had 2,022 Investor Partners holding 4,497 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 December 31, 2007, 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 therefrom 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, adjusted for units purchased by the Managing General Partner, 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 natural gas production, or significant increases in the production of oil and natural 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.

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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.

Item 6. Selected Financial Data

The selected financial data presented below has been derived from audited financial statements of the Partnership appearing elsewhere herein this Form 10-K. This information is only a summary and should be read in conjunction with "Management Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and related notes thereto contained in this report.


		Period from
		September 7, 2006
	Year Ended	(date of inception) to
	December 31, 2007	December 31, 2006


Oil and gas sales	$ 31,942,229	$ 1,228,684
Oil and gas price risk management loss, net	(1,145,968)	(408)
Costs and expenses	21,666,752	2,721,058
Loss on impairment of oil and gas properties	2,445,617	7,129,683
Exploratory dry hole costs	8,132,943	-
Net loss	(1,282,915)	(7,456,539)
Allocation of net loss
Managing general partner	(474,679)	(2,259,749)
Investor partners	(808,236)	(5,196,790)
Investor partners per unit	(180)	(1,156)
Total assets (as of end of period)	95,815,846	113,026,550

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Special note regarding forward looking statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 regarding 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 natural 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 natural 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 natural 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, and its other filings with the Securities and Exchange Commission, or SEC. 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 September 7, 2006 with initial contributions of $89,940,527 from the Investor Partners and a cash contribution of $38,912,342 from the Managing General Partner. After payment of syndication costs of $9,084,039 and a one-time management fee to PDC of $1,349,108, the Partnership had available cash of $118,419,722 to commence Partnership oil and gas well drilling activities.

The Partnership began exploration and development activities immediately after funding. The Partnership was billed by PDC for exploration and development activities from the inception of the Partnership through December 31, 2006. At December 31, 2006, amounts remaining from the funding of the Partnership were paid to PDC as a prepayment for drilling of oil and natural gas wells on behalf of the Partnership under the drilling and operating agreement. On September 7, 2006 PDC commenced drilling wells on prospects designated by PDC. As of December 31, 2007, a total of ninety-seven wells have been drilled, predominantly in Colorado, of which ninety-one are producing and six are dry holes. These ninety-seven wells are the only wells the Partnership will drill, because all of the capital contributions have been utilized. The completed wells produce primarily natural gas, with some associated crude oil. Sales of produced natural gas and oil commenced during the fourth quarter of 2006 as wells were connected to pipelines. Production and sales increased in 2007 as additional wells were 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 for year ended December 31, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006.

	Period from
	September 7, 2006
	(date of inception) to			For the Quarter Ended
(Unaudited)	September 30,			December 31,			March 31,			June 30,			September 30,			December 31,
	2006			2006			2007			2007			2007			2007

Number of Producing Wells:		-			25			32			64			91			91

Production:
Natural gas (Mcf)		-			52,706			273,331			848,953			1,157,075			857,545
Oil (Bbl)		-			16,728			59,138			104,673			74,864			58,802
Natural gas equivalents (Mcfe)		-			153,074			628,159			1,476,991			1,606,259			1,210,357

Average Selling Price:
Natural gas (per Mcf)	$	-		$	5.92		$	5.60		$	5.03		$	3.91		$	4.90
Oil (per Bbl)	$	-		$	54.79		$	45.22		$	53.86		$	66.08		$	70.71
Natural gas equivalents (per Mcfe)	$	-		$	8.03		$	6.69		$	6.71		$	5.90		$	6.91

Average Costs (per Mcfe):
Production and operating costs	$	-		$	1.24		$	1.18		$	1.05		$	1.12		$	1.22
Depreciation, depletion and amortization	$	-		$	6.55		$	3.22		$	3.24		$	3.02		$	3.16

Revenues:
Oil and gas sales	$	-		$	1,228,684		$	4,204,666		$	9,904,797		$	9,470,701		$	8,362,065
Oil and gas price risk management
(loss) gain, net		-			(408	)		(60,931	)		80,000			524,671			(1,689,708	)
Total revenues		-			1,228,276			4,143,735			9,984,797			9,995,372			6,672,357

Costs and Expenses:
Production and operating costs		-			189,069			740,263			1,544,329			1,799,505			1,473,230
Management fee		1,349,108			-			-			-			-			-
Direct costs		114			176,499			21,421			19,536			129,973			416,125
Depreciation, depletion and amortization		-			1,003,120			2,021,542			4,778,643			4,853,220			3,822,985
Accretion of asset retirement obligation		-			3,148			8,451			9,847			9,325			9,229
Loss on impairment of oil and
gas properties		-			7,129,683			1,135,208			1,310,409			-			-
Exploratory dry hole costs		-			-			3,395,210			3,150,266			1,577,101			10,366
Total costs and expenses		1,349,222			8,501,519			7,322,095			10,813,030			8,369,124			5,741,063

(Loss) income from operations		(1,349,222	)		(7,273,243	)		(3,178,360	)		(828,233	)		1,626,248			931,294

Interest expense		-			(15	)		(1,200	)		(1,927	)		(2,058	)		(2,358	)
Interest income		232,642			933,299			8,545			49,639			36,179			79,315

Net (loss) income	$	(1,116,580	)	$	(6,339,959	)	$	(3,171,015	)	$	(780,521	)	$	1,660,369		$	1,008,251

Cash distributions	$	-		$	-		$	-		$	4,255,017		$	8,877,047		$	7,513,464

Definitions

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

·	Mcf – One thousand cubic feet

·	Mcfe – One thousand cubic feet of natural 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

Oil and gas sales, excluding the impact of commodity based derivatives, which are included in oil and gas price risk management (loss), net, in the statement of operations, increased to $31,942,229 in 2007 from $1,228,684 in 2006 as the number of producing wells for the Partnership increased from twenty-five to ninety-one. The average selling price for natural gas declined to $4.63 per Mcf during 2007 from $5.92 per Mcf in 2006. The average selling price for oil per Bbl increased to $58.55 per Bbl in 2007 from $54.79 per Bbl in 2006.

Oil and Gas Pricing

Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production effectively. Natural gas and oil prices have been among the most volatile of all commodity prices. These price variations have a material impact on our financial results. Natural gas and oil 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. 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 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. This decline hit a low of $1.11 per Mcf in October 2007. In response to this low price, the Partnership temporarily shut in 11 wells in October 2007, resulting in a loss in production and revenue for the Partnership. Production on these wells resumed between November 1 and November 5, 2007, when natural gas prices rose to $3.61 per Mcf, and as of December 31, 2007, no wells were shut-in. Since December 31, 2007, oil and natural gas prices have increased dramatically above prices experienced during 2007. The Partnership's sales prices for natural gas and oil are subject to increases and decreases based on various market sensitive indices and are highly dependant on the balance between supply and demand. The Partnership's future revenues from oil and natural gas sales are affected by changes in prices.

Oil and gas price risk management loss, net

The Partnership manages oil and gas price risk though the use of derivative instruments to provide protection from declining prices. Realized and unrealized gains and losses resulting from derivative positions are reported on the statement of operations as oil and gas price risk management (loss) gain, net. The net gains/losses are comprised of the change in fair value of derivative positions related to the Partnership’s production for derivative contracts entered into by the Managing General Partner on behalf of the Partnership. In periods of rising prices, the Partnership will generally record losses on its derivative positions as the fair values exceed contract prices related to the Partnership’s oil and gas sales. Conversely, in periods of decreasing prices, the Partnership will generally recognize gains on its derivative positions. Since December 31, 2007, through the filing of this report, we continue to experience increased oil and gas prices resulting in expected additional losses in realized and unrealized derivative positions. The following table presents the realized and unrealized gains and losses recorded for each of the identified periods:

	Period from
	September 7, 2006
	(date of inception)			Quarter ended										Year ended
	to December 31,			March 31			June 30,		September 30,		December 31,			December 31,
	2006			2007			2007		2007		2007			2007
Realized gain	$	-		$	-		$	4,571	$	46,068	$	156,786		$	207,425
Unrealized (loss) gain		(408	)		(60,932	)		75,429		478,587		(1,846,494	)		(1,353,410	)
Oil and gas price risk management (loss) gain, net	$	(408	)	$	(60,932	)	$	80,000	$	524,655	$	(1,689,708	)	$	(1,145,985	)

The majority of the unrealized loss recognized during the quarter and year ended December 31, 2007 is the result of oil price increases in excess of the $84.20 contract price for oil production swap contracts entered into in October 2007.

Production and Operating Costs

The Partnership incurred production and operating costs of $5,557,327 for the year ended December 31, 2007 and $189,069 for the period from September 7, 2006 (date of inception) to December 31, 2006 as the number of producing wells for the Partnership increased from twenty-five to ninety-one.

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Direct Costs

Direct costs consist primarily of audit and consulting fees relating to the filing and subsequent amendment of the Partnership’s Registration on Form 10 and also include accruals for certain legal matters (see Note 8 to the accompanying financial statements).

Depreciation, Depletion and Amortization

The Partnership recorded depreciation, depletion and amortization expense of $15,476,390 for the year ended December 31, 2007 and $1,003,120, for the period from September 7, 2006 (date of inception) to December 31, 2006 as the number of producing wells for the Partnership increased from twenty-five to ninety-one.

Loss on Impairment of oil and gas properties

The Partnership recorded impairment losses of $2,445,617 for the year ended December 31, 2007 and $7,129,683 for the period from September 7, 2006 (date of inception) to December 31, 2006 resulting from production activities in the Bakken and Nesson fields in North Dakota.

Exploratory dry hole costs

The Partnership incurred exploratory dry hole costs of $8,132,943 during the year ended December 31, 2007 resulting from three exploratory wells in Colorado and two exploratory wells in North Dakota.

The Jepson 11-19h exploratory well in the Bakken field in North Dakota was determined to be an economic dry hole in the first quarter of 2007. Although the well does produce oil, the amount of production was deemed to be insignificant and thus the well was determined to be a dry hole. The Brnak 22-11 exploratory well in Colorado was also determined to be a dry hole. During the first quarter of 2007, the Partnership expensed $3,395,210 of exploratory dry hole costs related to these two wells.

During the second quarter of 2007, the Anderson 11-24h exploratory well in Nesson field in North Dakota was determined to be a dry hole. The Partnership expensed $3,150,266 of exploratory dry hole costs related to this well in the second quarter of 2007.

During the third quarter of 2007, the Wagner 33-23 and Sirios 22-1 exploratory wells in the Wattenberg field in Colorado were determined to be economic dry holes, as the cost of extending the existing gas pipeline to bring the oil and natural gas produced by these wells to market was determined to be economically unfeasible, given the current market prices and estimated reserves for the two wells. The Partnership expensed $1,577,101 of exploratory dry hole costs related to these wells in the third quarter of 2007.

Liquidity and Capital Resources

The Partnership had working capital of $5,091,880 and $2,026,810 at December 31, 2007 and 2006, respectively, which generally represents the receivables from oil and gas sales for the preceding three months offset by corresponding accounts payable and accrued expenses for the same period.

As the Partnership has completed its drilling activities as of December 31, 2007, the Partnership’s operations are expected to be conducted with available funds and revenues generated from oil and gas production activities. Except for amounts due to the Managing General Partner as of December 31, 2007, no additional funds will be used at this time for drilling activities. As such, the Partnership’s liquidity may be impacted by fluctuating oil and natural gas prices, as noted in “Item 1A, Risk Factors.” The Partnership initiated monthly cash distributions to investors in May 2007 and has distributed $20,645,528 of operating cash flows through December 31, 2007.

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Changes in market prices for oil and natural gas directly affect the level of our cash flow from operations. While a decline in oil and natural gas prices would affect the amount of cash flow that would be generated from operations, we had oil and natural gas hedges in place, as of December 31 2007, covering 83% of our expected oil production and 40% of our expected natural gas production in 2008, thereby providing price certainty for a substantial portion of our 2008 cash flow. Our current hedging positions could change based on changes in oil and natural gas futures markets, the view of underlying oil and natural gas supply and demand trends and changes in volumes produced. Our oil and natural gas hedges as of December 31, 2007, are detailed in “Note 3 – Transactions with Managing General Partner and Affiliates” in the notes to the financial statements of this report.

No bank borrowings are anticipated until such time as recompletions of the Codell formation in the Wattenberg Field wells are undertaken by the Partnership, which is expected to occur in 2011 or later.

Contractual Obligations and Contingent Commitments

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



	Payments due by period
Contractual Obligations and		Less than			More than
Contingent Commitments	Total	1 year	1-3 years	3-5 years	5 years


Asset Retirement Obligations	$ 775,652	-	-	-	$ 775,652

Critical Accounting Policies and Estimates

The Partnership has 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, 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:

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.

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Oil and Gas Property Accounting

The process of estimating and evaluating oil and natural 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.

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.

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Revenue Recognition

Sales of natural gas are recognized when natural 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. Natural 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 natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Partnership’s revenues from the sale of natural gas 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 natural gas contracts are customary in the industry.

The Managing General Partner currently uses the “Net-Back” method of accounting for transportation arrangements of natural 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 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.

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.

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.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Market-Sensitive Instruments and Risk Management

The Partnership's primary market risk exposure is commodity price risk. This exposure is discussed in detail below:

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Commodity Price Risk

The Partnership is 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 and marketing activities. 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.

Derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership and are reported on the Partnership’s balance sheet at fair value as a net short-term or long-term receivable or payable due from or payable to the Managing General Partner. Changes in the fair value of the Partnership’s share of derivatives are recorded in the statement of operations.

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.

Economic Hedging Strategies

The results of the Partnership’s 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 December 31, 2007, our oil and natural gas derivative instruments were comprised of futures, swaps and collars. These instruments generally consist of CIG-based contracts for Colorado natural gas production and NYMEX-based swaps for our Colorado and North Dakota 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.

The Managing General Partner 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 highly effective in achieving the risk management objectives for which they were intended.

The following table presents monthly average CIG and NYMEX closing prices for natural gas and oil in 2007 and 2006, as well as average sales prices we realized for the respective commodity.

		Period from
		September 7, 2006
	Year Ended	(date of inception) to
	December 31, 2007	December 31, 2006

Average index closing price
Natural gas (per Mmbtu)
CIG	$ 3.97	$ 4.80

Oil (per Bbl)
NYMEX	$ 69.79	$ 61.81

Average sales price
Natural gas	$ 4.63	$ 5.92
Oil	$ 58.55	$ 54.79

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Based on a sensitivity analysis as of December 31, 2007, it was estimated that a 10% increase in oil and natural gas prices over the entire period for which we have derivatives currently in place would result in an increase in unrealized losses of $2,956,000 and a 10% decrease in oil and natural gas prices would result in a decrease in unrealized losses of $2,956,000.

See “Note 2 - Summary of Significant Accounting Policies”, and “Note 3 - Transactions with Managing General Partner and Affiliates” in the notes to the financial statements included in this report for additional disclosure regarding derivative instruments including, but not limited to, a summary of the open derivative option and purchase and sales contracts as of December 31, 2007.

Disclosure of Limitations

As the information above incorporates only those exposures that exist at December 31, 2007, 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 8. Financial Statements and Supplementary Data

The financial statements are attached to this Form 10-K beginning at page F-1.

Supplemental financial information required by this Item can be found in “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A. Controls and Procedures

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

This annual report on Form 10-K does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of the Partnership's registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

The Partnership is not currently required to report on the effectiveness of its internal control over financial reporting, and the Partnership's independent accounting firm is not currently required to report on the Managing General Partner's assessment of the Partnership's internal control over financial reporting.

While the Partnership is not currently required to report on the effectiveness of its internal control over financial reporting until its fiscal year ending December 31, 2008, the Partnership's Managing General Partner was required to assess the effectiveness of its internal control over financial reporting as of December 31, 2007. As discussed in the Manager General Partner's Annual Report on Form 10-K for the year ended for December 31, 2007, filed with the Securities and Exchange Commission on March 20, 2008, the Managing General Partner did not maintain effective controls as of December 31, 2007, over:

The completeness, accuracy, validity and restricted access of certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts. Specifically, the Company 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.

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Effective policies and procedures, or personnel with sufficient technical expertise to record derivative activities in accordance with generally accepted accounting principles. Specifically, the Company's internal control processes did not ensure the completeness and accuracy of the derivative activities in the fourth quarter.

The Managing General Partner concluded that its disclosure controls and procedures were not effective as of December 31, 2007, due to the existence of the material weaknesses described above.

As reported in its Annual Report on Form 10-K for the year ended December 31, 2007, the Managing General Partner has made the following change during the quarter ended December 31, 2007 in its internal control over financial reporting that it believes has materially affected, or is reasonably likely to materially affect, the Partnership's internal control over financial reporting:

·	Installed new software supporting the derivative valuation process. The new system enhanced the existing internal controls framework over reporting more accurate information by automating a previously manual control.

During the third quarter of 2007, and continuing through the filing of this report, the Managing General Partner made the following change in its internal control over financial reporting that has materially affected, or is reasonably likely to materially affect our internal controls over financial reporting:

·	Installed new software supporting the accounts payable process as part of a broader financial reporting system implementation. The new system enhanced the existing internal control framework over accounts payable and cash distribution process by automating several of the previously manual controls.

Additionally, during the first quarter of 2007, and continuing through the filing of this report, the Managing General Partner implemented the following changes in its internal control over financial reporting:

·	Reinforced reconciliation procedures to ensure the timely reconciliation, review and adjustments to significant balance sheet and income statement accounts;

·	Developed and approved extensive policies and procedures concerning the controls over financial reporting for derivatives;

·	Provided additional training regarding derivatives for key personnel; and

·	Developed a review process to ensure proper accounting for oil and gas properties, specifically the capitalization of costs and calculation of depreciation and depletion.

The Managing General Partners continues to evaluate the ongoing effectiveness and sustainability of the changes they have made in internal control, and, as a result of the ongoing evaluation, may identify additional changes to improve internal control over financial reporting. For additional information regarding the material weaknesses of the Managing General Partner, please refer to its Annual Report on Form 10-K for the year ended December 31, 2007 referenced above.

Because of the Managing General Partner's material weaknesses, the Partnership performed additional procedures to ensure that its financial statements for the year ended December 31, 2007, were fairly presented in all material respects in accordance with generally accepted accounting principles.

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Item 9B. Other Information

None

PART III

Item 10. Directors, 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 natural 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 natural 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.

-28-

Petroleum Development Corporation

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

Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires

Steven R. Williams	57	Chairman, Chief Executive Officer and Director	1983	2009

Richard W McCullough	56	Vice Chairman, President, Chief Financial Officer and Director	2007	2008

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.	45	Senior Vice President Exploration and Production	-	-

Vincent F. D'Annunzio	55	Director	1989	2010

Jeffrey C. Swoveland	53	Director	1991	2008

Kimberly Luff Wakim	49	Director	2003	2009

David C. Parke	41	Director	2003	2008

Anthony J. Crisafio	55	Director	2006	2009

Joseph E. Casabona	64	Director	2007	2008

Larry F. Mazza	47	Director	2007	2008

Steven R. Williams was elected Chairman and Chief Executive Officer in January 2004. Mr. Williams served as President from March 1983 until December 2004 and has been a Director of PDC since 1983.

Richard W. McCullough was appointed President in March 2008, elected Vice Chairman of PDC's Board of Directors in December 2007, 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, natural 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 natural 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.

Darwin L. Stump was 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.

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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. Amidon was appointed General Counsel and Secretary in July 2007. Prior to his current position, Mr. Amidon was employed by Wheeling-Pittsburgh Steel Corporation beginning in July 2004; he served in several positions including General Counsel and Secretary. Prior to his employment with Wheeling-Pittsburgh Steel, Mr. Amidon worked for J&L Specialty Steel Inc. from 1992 through July 2004 in positions of increasing responsibility, including General Counsel and Secretary. Mr. Amidon practiced with the Pittsburgh law firm of Buchanan Ingersoll PC from 1986 through 1992.

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. Mr. D’Annuzio has served as a Director since 1989.

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 natural 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 natural gas and oil company. Mr. Swoveland has served as a Director since 1991.

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. Ms. Wakim has served as a Director since 2003.

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 Nicolaus. 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. Mr. Parke has served as a Director since 2003.

Anthony J. Crisafio was elected to the Board in October 2006. Mr. 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 was elected to the Board in October 2007 by the Board of Directors. Mr. Casabona served as Executive Vice President and member of the Board of Directors of Denver based Energy Corporation of America, or ECA, from 1985 to his retirement earlier this year. ECA combines Appalachian Basin natural gas development, deep exploration, marketing, and pipeline gathering and transportation to industrial end users, utility purchasers and other customers with higher risk, higher reward exploratory drilling in Texas and internationally.

Larry F. Mazza was elected to the Board in October 2007 by the Board of Directors. Mr. 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). Jeffrey C. Swoveland chairs the Audit Committee. Mr. Swoveland and the other audit committee members, with the exception of Mr. Parke, qualify as audit committee financial experts and are independent of management.

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Item 11. Executive Compensation

The Partnership does not have any employees or executives of its own. None of PDC's officers or directors receive any direct remuneration, compensation or reimbursement from the Partnership. These persons receive compensation solely from PDC. The 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.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

As of December 31, 2007, the Partnership had 4,497 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 December 31, 2007, PDC has not repurchased any Partnership interests.

PDC owns a 37% partnership interest in the Partnership.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Compensation to the Managing General Partner and Affiliates

Recipient	Transaction	Compensation September 7, 2006 (date of inception) to December 31, 2006	Compensation Year Ended December 31, 2007
Managing General Partner	Drilling compensation	$3,244,129	$10,117,387
Managing General Partner	Operator's monthly per-well charges and services	$28,102	$508,340
Managing General Partner	Purchased partnership interest	$38,912,342	$ -
Managing General Partner	Sale of leases to the partnership	$630,091	$908,880
Managing General Partner	Contract drilling rates	$25,116,964	$79,387,844
Managing General Partner	Gathering, compression and processing	$14,465	$280,403
Managing General Partner and Affiliates	Gas marketing, supplies and equipment	$33,029	$2,336,455
Managing General Partner	Direct costs	$176,613	$557,083
Affiliate	Organization and offering costs	$9,084,039	$ -
Managing General Partner	One-time management fee	$1,349,108	$ -

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Drilling Costs - 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. The Managing General Partner charges a drilling overhead rate of 1½% of drilling authority for expenditure (“AFE”) for each well. This overhead rate is included in the total well cost for the drilling compensation calculation. 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

Per Well Charges - 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 interpositioning 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 natural 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.

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Natural Gas and Oil Revenues - The limited partnership agreement provides for the allocation of revenues from natural gas and oil production 63% to the Investors 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 “Participation in Costs and Revenues” in Item 9 below. PDC has contributed capital of $38,912,342 to the Partnership as of December 31, 2007 in exchange for the 37% allocation of revenues.

Sale of Leases to the Partnership – The managing general partner sells undeveloped prospects 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.

Direct Costs – 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.

Organization and Offering Costs – The Partnership reimbursed the managing general partner for dealer manager commissions, discounts, and due diligence costs, marketing and support expenses and wholesaling fees, up to 10.5% of subscriptions as outlined in the partnership agreement.

Management Fee – 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.

Gathering, Compression and Processing Fees - Under the limited partnership agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the natural gas produced by the Partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area from the point the 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 natural gas.

Gas Marketing, Supplies and Equipment - PDC 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.

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.

Other Agreements and Arrangements

Executive officers of the Managing General Partner are eligible to invest in a Board-approved executive drilling program, as approved by the Board of Directors

These executive officers may profit from their participation in the executive drilling program because they invest in wells at cost and do not have to pay drilling compensation, management fees or broker commissions and therefore obtain an interest in the wells at a reduced price than that which is generally charged to the investing partners in a Partnership. Other investors participating in drilling through a Partnership are generally charged a profit or markup above the cost of the wells; management fees and commissions at rates which are generally similar to those for this Partnership outlined on “Item 13, Compensation to the Managing General Partner and Affiliates.” As a result, the executive officers realize a benefit not generally available to other investors.

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Through the executive drilling program, certain executive officers have invested in the wells owned by the Partnership. Their ownership by each executive in Partnership wells varies depending on when the well was drilled and the amount of funds invested in the program and ranges from .014% up to ..038%. The Board believes that having the executive officers invest in wells with the Company and other investors helps to create a commonality of interests much like share ownership creates a commonality of interests between the shareholders and executive officers.

Director Independence

The Partnership has no directors. The Partnership is managed by the Managing General Partner. See Item 10 above.

Item 14. Principal Accounting Fees and Services

For the year ended December 31, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006, there were billings from the Partnership’s independent auditors, Schneider Downs and Co., Inc. (“Schneider Downs”) of $327,661 and $151,331 for audit fees. Audit fees include amounts billed for professional services rendered by Schneider Downs for the audit of the Partnership’s financial statements in its Form 10, including reviews of the condensed financial statements included in the Partnership’s quarterly reports on Form 10-Q for the year ended December 31, 2007. The 2007 audit fees also include fees billed for professional services rendered by Schneider Downs for the audit of the financial statements included in the Partnership’s Form 10/A for the period from September 7, 2006 (date of inception) to December 31, 2006. For each period, there were no billing for audit-related fees, tax fees or all other fees.

Audit Committee Pre-Approval Policies and Procedures

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

-34-

Item 15. Exhibits, Financial Statement Schedules

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

(b) Exhibits.

Exhibit No.		Description
3.1		Limited Partnership Agreement (incorporated by reference to Exhibit No. 3 of Amendment No. 1 to Form 10-12G/A, SEC File number 000-53787)

3.2		Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law (incorporated by reference to Exhibit No. 3.1 of Amendment No. 1 to Form 10-12G/A, SEC File number 000-53787)

10.1		Form of assignment of leases to the Partnership (incorporated by reference to Exhibit #10.1 of Amendment No. 1 to Form 10-12G/A, SEC File number 000-53787)

10.2		Drilling and operating agreement between PDC as managing general partner and the Partnership (incorporated by reference to Exhibit #10.2 of Amendment No. 1 to Form 10-12G/A, SEC File number 000-53787)

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

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

32.1		Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Rockies Region 2006 Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By /s/ Steven R. Williams

Steven R. Williams

Chairman and Chief Executive Officer

April 7, 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	Chairman, Chief Executive Officer and	April 7, 2008
Steven R. Williams	Director of Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(principal executive officer)

/s/ Richard W. McCullough	Chief Financial Officer and Director	April 7, 2008
Richard W. McCullough	Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(principal financial officer)

/s/ Darwin L. Stump	Chief Accounting Officer	April 7, 2008
Darwin L. Stump	Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(principal accounting officer)

/s/ Jeffrey C. Swoveland	Director	April 7, 2008
Jeffrey C. Swoveland	Petroleum Development Corporation,
	Managing General Partner of the Registrant

/s/ Anthony J. Crisafio	Director	April 7, 2008
Anthony J. Crisafio	Petroleum Development Corporation

/s/ Joseph E. Casabona	Director	April 7, 2008
Joseph E. Casabona	Petroleum Development Corporation

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Index to Financial Statements


Report of Independent Registered Public Accounting Firm		F-2

Balance Sheets – December 31, 2007 and December 31, 2006		F-3

Statements of Operations – For the Year Ended December 31, 2007
and Period from September 7, 2006 (Date of Inception) to December 31, 2006		F-4

Statements of Cash Flows – For the Year Ended December 31, 2007
and Period from September 7, 2006 (Date of Inception) to December 31, 2006		F-5

Statements of Partners' Equity –For the Year Ended December 31, 2007
and Period from September 7, 2006 (Date of Inception) to December 31, 2006		F-6

Notes to Financial Statements		F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners

Rockies Region 2006 Limited Partnership:

We have audited the accompanying balance sheets of Rockies Region 2006 Limited Partnership as of December 31, 2007 and 2006 and the related statements of operations, partners’ equity and cash flows for the year ended December 31, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits 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. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal controls over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rockies Region 2006 Limited Partnership as of December 31, 2007 and 2006, and the results of its operations and its cash flows for the year ended December 31, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Schneider Downs & Co., Inc.

Pittsburgh, Pennsylvania

April 7, 2008

F-2

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Balance Sheets

December 31, 2007 and 2006

Assets	2007			2006


Current assets:
Cash and cash equivalents	$	1,183,810		$	1,154,594
Accounts receivable oil and gas sales		8,524,415			1,228,684
Due from Managing General Partner - derivatives, current portion		-			1,549
Interest receivable		40,000			-
Total current assets		9,748,225			2,384,827

Oil and gas properties, successful efforts method		101,950,453			21,835,420
Wells in progress		-			89,428,539
		101,950,453			111,263,959
Less accumulated depreciation, depletion and amortization		(15,882,832	)		(623,946	)
		86,067,621			110,640,013

Noncurrent assets:
Finance charges		-			238
Due from Managing General Partner - derivatives		-			1,472
Total noncurrent assets		-			1,710

Total Assets	$	95,815,846		$	113,026,550


Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	598,390		$	113,473
Due to Managing General Partner - derivatives		1,080,170			-
Due to Managing General Partner - other		2,977,786			244,544
Total current liabilities		4,656,346			358,017

Asset retirement obligation		775,652			356,242

Partners' equity		90,383,848			112,312,291

Total Liabilities and Partners' Equity	$	95,815,846		$	113,026,550


See accompanying notes to financial statements.

F-3

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Statements of Operations

For the Year Ended December 31, 2007 and
Period from September 7, 2006 (date of inception) to December 31, 2006

				Period from
				September 7, 2006
				(date of inception)
				to December 31,
	2007			2006

Revenues:
Oil and gas sales	$	31,942,229		$	1,228,684
Oil and gas price risk management loss, net		(1,145,968	)		(408	)
Total revenue		30,796,261			1,228,276

Costs and expenses:
Production and operating costs		5,557,327			189,069
Direct costs		596,183			176,613
Depreciation, depletion and amortization		15,476,390			1,003,120
Accretion of asset retirement obligations		36,852			3,148
Loss on impairment of oil and gas properties		2,445,617			7,129,683
Exploratory dry hole costs		8,132,943			-
Management fee		-			1,349,108
Total costs and expenses		32,245,312			9,850,741

Loss from operations		(1,449,051	)		(8,622,465	)

Interest expense		(7,543	)		(15	)
Interest income		173,679			1,165,941

Net loss	$	(1,282,915	)	$	(7,456,539	)

Net loss available to Investor Partners	$	(808,236	)	$	(5,196,790	)

Net loss per Investor Partner unit	$	(180	)	$	(1,156	)

Investor Partner units outstanding		4,497			4,497

See accompanying notes to financial statements.

F-4

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Statements of Cash Flows

For the Year Ended December 31, 2007 and
Period from September 7, 2006 (date of inception) to December 31, 2006

				Period from
				September 7, 2006
				(date of inception)
				to December 31,
	2007			2006

Cash flows from operating activities:

Net loss	$	(1,282,915	)	$	(7,456,539	)
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities:
Loss on impairment of oil and gas properties		2,445,617			7,129,683
Depreciation, depletion and amortization		15,476,390			1,003,120
Accretion of asset retirement obligation		36,852			3,148
Unrealized loss on derivative transactions		1,342,708			408
Exploratory dry hole costs		8,132,943			-
Changes in operating assets and liabilities:
Increase in due from Managing General Partner - derivatives		(259,517	)		(3,429	)
Increase in accounts receivable - oil and gas sales		(7,295,731	)		(1,228,684	)
Increase in interest receivable		(40,000	)		-
Decrease (increase) in financing charges		238			(238	)
Increase in accounts payable and accrued expenses		484,917			113,473
Increase in due to Managing General Partner - other		1,633,242			244,544
Net cash provided by (used in) operating activities		20,674,744			(194,514	)

Cash flows from investing activities:
Expenditures for oil and gas properties		-			(118,419,722	)
Net cash used in investing activities		-			(118,419,722	)

Cash flows from financing activities:
Investor Partners' contributions		-			89,940,527
Managing General Partner contribution		-			38,912,342
Syndication costs paid		-			(9,084,039	)
Distributions to partners		(20,645,528	)		-
Net cash (used in) provided by financing activities		(20,645,528	)		119,768,830

Net increase in cash and cash equivalents		29,216			1,154,594
Cash and cash equivalents at beginning of period		1,154,594			-
Cash and cash equivalents at end of period	$	1,183,810		$	1,154,594

Supplemental disclosure of non-cash activity:
Asset retirement obligation, with a corresponding increase
to oil and gas properties	$	382,558		$	353,094

Investment in oil and gas properties	$	1,100,000		$	-

See accompanying notes to financial statements.

F-5

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Statements of Partners' Equity

For the Year Ended December 31, 2007 and
Period from September 7, 2006 (date of inception) to December 31, 2006


				Managing
	Investor			General
	Partners			Partner			Total


Partners' initial contributions	$	89,940,527		$	38,912,342		$	128,852,869

Syndication costs		(9,084,039	)		-			(9,084,039	)

Net loss		(5,196,790	)		(2,259,749	)		(7,456,539	)

Balance, December 31, 2006		75,659,698			36,652,593			112,312,291

Distributions to Partners		(13,006,686	)		(7,638,842	)		(20,645,528	)

Net loss		(808,236	)		(474,679	)		(1,282,915	)

Balance, December 31, 2007	$	61,844,776		$	28,539,072		$	90,383,848


See accompanying notes to financial statements.

F-6

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

(1) Organization

The Rockies Region 2006 Limited Partnership (the “Partnership”) was organized as a limited partnership on September 7, 2006, 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 47.25 units of limited partner interests and 4449.78 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 were converted into units of limited partner interests and thereafter became 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.

(2) Summary of Significant Accounting Policies

Partnership Financial Statement Presentation Basis

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.

Cash and Cash Equivalents

For purposes of the statement of cash flows, 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.

Allowance for Doubtful Accounts

As of December 31, 2007 and 2006, the Partnership did not record an allowance for doubtful accounts. The Partnership sells substantially all of its oil and natural gas to customers who purchase oil and natural 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 year ended December 31, 2007 or the period from September 7, 2006 (date of inception) to December 31, 2006.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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 new reserve reports from independent petroleum engineers annually as of December 31 of each year. See “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)” 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 natural 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 natural 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 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 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. 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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ROCKIES REGION 2006 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. The Partnership recognized impairment losses of $2,445,617 and $7,129,683 for the year ended December 31, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006.

Revenue Recognition

Sales of natural gas are recognized when natural 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. Natural 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 natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Partnership’s revenues from the sale of natural gas 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 natural gas contracts are customary in the industry.

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.

The Partnership sold natural gas and oil to two customers, Teppco Crude Oil, L.P. and Williams Production RMT, which accounted for 75% and 18%, respectively, of the Partnership’s total natural gas and oil sales for the period ended December 31, 2006. These same two customers accounted for 45% and 35%, respectively, of the Partnership’s total natural gas and oil sales for the year ended December 31, 2007.

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ROCKIES REGION 2006 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 6 – 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, they are reported on the balance sheet as a net short-term or long-term receivable due from or payable due to the Managing General Partner. The Partnership did not recognize any realized gains or losses on derivative contracts as of December 31, 2006, thus no amounts are due to/from the Managing General Partner on closed derivative positions at December 31, 2006. The Partnership realized a gain of $207,425 on derivative contracts as of December 31, 2007. This amount is included in the balance due to the Managing General Partner - Other.

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. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Managing General Partner.

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.

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.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

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 September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements,” which replaces several existing pronouncements, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Partnership is currently evaluating the impact the provisions of SFAS No. 157 will have, if any, on its financial statements when adopted in 2008.

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. The Partnership is currently evaluating the impact the provisions of SFAS No. 159 will have, if any, on its financial statements when adopted in 2008.

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 Partnership is currently evaluating the impact the provisions of FIN No. 39-1 will have, if any, on its financial statements when adopted in 2008.

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:

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

·	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. The adoption of the provisions of SFAS No. 161 in 2009 is not expected to have a material impact on the Partnership's 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.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes: an Interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement principles for financial statement disclosure of tax positions taken or expected to be taken on a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. The provisions FIN 48 did not have a material impact on the Partnership's financial statements.

In September 2006, the Staff of the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) No. 108, “Financial Statements – Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”. SAB 108 provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether current year’s financial statements are materially misstated. SAB 108 requires registrants to quantify misstatements using both an income statement (“rollover”) and balance sheet (“iron curtain”) approach and evaluate whether either approach results in a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. If prior year errors that had been previously considered immaterial now are considered material based on either approach, no restatement is required so long as management properly applied its previous approach and all relevant facts and circumstances were considered. If prior years are not restated, the cumulative effect adjustment is recorded in opening accumulated earnings as of the beginning of the fiscal year of adoption. SAB 108 is effective for fiscal years ended on or after November 15, 2006. The provisions of SAB 108 did not have a material impact on the Partnership’s financial statements.

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ROCKIES REGION 2006 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 December 31, 2007 and 2006, the Partnership owed the Managing General Partner $2,977,786 (including approximately $1,100,000 related to completion of drilling cost) and $244,544, respectively. As a result of derivative transactions executed by the Managing General Partner on behalf of the Partnership, there were also short-term derivative (payables) receivables of $(1,080,170) and $1,549 and long-term derivative receivables of $0 and $1,472 at December 31, 2007 and 2006.

The following table presents reimbursements and service fees paid by the Partnership to PDC or its affiliates for year ended December 31, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006.

		Period from
		September 7, 2006
	Year Ended	(date of inception) to
	December 31, 2007	December 31, 2006


Payment of drilling and completion costs	$ -	$ 118,419,722
Syndication costs*	-	1,816,808
Management fee	-	1,349,108
Well operations fees	508,340	28,102

* Consists of organization and offering costs, including costs of organizing and selling the offering (including total underwriting and brokerage discounts and commissions), expenses for printing, mailing, salaries of employees while engaged in sales activity, charges of transfer agents, registrars, trustees, escrow holders, depositories, engineers and other experts, expenses of qualification of the sale of the securities under federal and state law, including accountants’ and attorneys’ fees and other front end fees.

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.

As described above, the Managing General Partner utilizes commodity-based derivative instruments, entered into on behalf of the Partnership, to manage a portion of the Partnership’s exposure to price risk from oil and natural gas sales. These instruments consist of CIG (Colorado Interstate Gas) index-based contracts for Colorado natural gas production and NYMEX (New York Mercantile Exchange) index-based contracts for Colorado and North Dakota oil production. These derivative instruments have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Managing General Partner receives for the volume of oil and natural gas to which the derivative relates.

The fair value of the Partnership’s share of commodity based derivatives was ($1,080,170) at December 31, 2007. The Partnership recognized in the statement of operations net realized and unrealized gains and losses on commodity based derivatives of $1,145,968 for year ended December 31, 2007. The following table summarizes the Partnership’s share of open derivative positions as of December 31, 2007.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

Open Derivative Contracts
Commodity	Type	Quantity Gas-Mmbtu (a) Oil-Bbl		Weighted Average Price		Fair Market Value

Partnership's share of positions as of December 31, 2007
Natural Gas	Floors		1,097,398	$	5.44	$	208,408
Natural Gas	Ceilings		971,407	$	10.26	$	(10,742	)
Oil	Fixed-Price Swaps		146,808	$	84.20	$	(1,277,836	)
Due From Managing General Partner - Derivatives, Total						$	(1,080,170	)

At December 31, 2007, the maximum term for the derivative positions listed above is 12 months.

(a) MMBtu - one million British thermal units. One British thermal unit is the heat required
to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

The fair value of the Partnership’s share of commodity based derivatives was $3,021 at December 31, 2006. The Partnership recognized in the statement of operations an unrealized loss on commodity based derivatives of $408 for the period from September 7, 2006 (date of inception) to December 31, 2006. The following table summarizes the Partnership’s share of open derivative positions as of December 31, 2006.

Open Derivative Contracts
Commodity	Type	Quantity Gas-Mmbtu Oil-Bbl		Weighted Average Price		Fair Market Value

Partnership's share of positions as of December 31, 2006:
Natural Gas	Cash Settled Option Sales		6,291	$	5.25	$	3,021
Due From Managing General Partner - Derivatives, Total						$	3,021

Partership's share of positions maturing within 12 months following December 31, 2006:
Natural Gas	Cash Settled Option Sales		2,517	$	5.25	$	1,549

Due From Managing General Partner - Derivatives, Short-term						$	1,549

At December 31, 2006, the maximum term for the derivative positions listed above is 15 months.

(4) Allocation of Partners’ Interests

The table below summarizes the participation of the Managing General Partner and the Investor Partners in the costs and revenues of the Partnership, taking into account the Managing General Partner's capital contribution, which is equal to a minimum of 43.07% of the Investor Partners’ initial capital.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

	Investor Partners	Managing General Partner
Partnership Costs

Organization Costs (a)	0%	100%
Broker-dealer Commissions and Expenses (a)	100%	0%
Management Fee (b)	100%	0%
Undeveloped Lease Costs	0%	100%
Tangible Well Costs	0%	100%
Intangible Drilling Costs (IDC)	100%	0%
Managing General Partner's Drilling Compensation	100%	0%
Direct Drilling and Compensation Costs, excluding Managing General Partner’s Drilling Compensation	63%	37%
Operating Costs (c)	63%	37%
Direct Costs (d)	63%	37%

Partnership Revenue

Sale of Oil and Gas Production	63%	37%
Sale of Productive Properties	63%	37%
Sale of Equipment	63%	37%
Sale of Undeveloped Leases	63%	37%
Interest Income	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.

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, which occurred in July 2007. 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. No partnership units can be repurchased under this provision by the Managing General Partner until thirty-six months after the date of the first distribution to the partners.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

(5) 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 September 7, 2006 with payments made for all planned drilling and completion costs for the Partnership made in December 2006. Costs capitalized for these activities at December 31, 2007 and December 31, 2006 are as follows:

		Period from
		September 7, 2006
		(date of inception) to
	December 31, 2007	December 31, 2006

Leasehold costs	$ 822,436	$ 313,808
Development costs	101,128,017	21,521,612
Wells in progress	-	89,428,539
	$ 101,950,453	$ 111,263,959

Wells in progress represents prepayments to the Managing General Partner for the exploration and development of oil and gas properties.

(6) Asset Retirement Obligations

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

		Period from
		September 7, 2006
	Year Ended	(date of inception) to
	December 31, 2007	December 31, 2006


Balance at beginning of period	$ 356,242	$ -
Obligations assumed with development activities	382,558	353,094
Accretion expense	36,852	3,148
Balance at end of period	$ 775,652	$ 356,242

The discount rate used in calculating the asset retirement obligation and related accretion vary from 5.10% to 5.55%, depending on the quarter in which the Partnership was required to record the retirement obligation for any specific well. These rates approximate the borrowing rate of the Managing General Partner for the quarter in which the retirement obligation was recorded.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

(7)	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 December 31, 2007 and 2006 regarding our estimated proved developed 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. 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 natural gas reserves we own. The Partnership's proved developed reserves include reserves related to future recompletions of wells in the Codell formation of 663,900 Bbls of oil and 2,870,500 Mcfs of natural gas and 103,900 Bbls and 1,352,600 Mcfs of natural gas at December 31, 3007 and 2006, respectively. An analysis of the change in estimated quantities of proved developed oil and gas reserves is shown below:

	Oil (Bbls)
	December 31,
	2007			2006

Proved developed reserves:
Beginning of year		960,700			-
Revisions of previous estimates		485,400			-
New discoveries and extensions		654,400			977,400
Production		(297,500	)		(16,700	)
End of Period		1,803,000			960,700

	Gas (Mcfs)
	December 31,
	2007			2006
Proved developed reserves:
Beginning of year		9,013,800			-
Revisions of previous estimates		7,894,600			-
New discoveries and extensions		10,571,300			9,066,500
Production		(3,136,400	)		(52,700	)
End of Period		24,343,300			9,013,800

In 2007, the Partnership recorded an upward revision to its previous estimate of proved reserves of approximately 10.8 Bcfe. The revision is primarily due to an increase of approximately 12.2 Bcfe and 1 Bcfe, respectively, due to asset performance and higher commodity prices, partially offset by a decrease of approximately 2.4 Bcfe due to increased operating costs.

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.”

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

	December 31,
	2007			2006

Future estimated cash flows	$	311,970,100		$	96,697,800
Future estimated production costs		(78,301,700	)		(29,902,600	)
Future estimated development costs		(12,218,400	)		(15,990,200	)
Future net cash flows		221,450,000			50,805,000
10% annual discount for estimated timing of cash flows		(103,770,000	)		(19,220,000	)
Standardized measure of discounted future
estimated net cash flows	$	117,680,000		$	31,585,000

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows for the year ended December 31, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006:

	December 31,
	2007			2006

Sales of oil and gas production, net of production costs	$	(26,384,900	)	$	(1,039,600	)
Net changes in prices and production costs		13,287,000			-
Extensions, discoveries, and improved recovery,
less related costs		47,012,000			32,625,700
Development cost incurred during the period		-			-
Revisions of previous quantity estimates		36,666,000			-
Accretion of discount		2,887,000			-
Timing and other		12,627,900			(1,100	)
Net change	$	86,095,000		$	31,585,000

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.

(8)	Commitments and Contingencies

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 natural gas produced from wells operated by the Managing General Partner in the State of Colorado (the "Droegemueller Action"). The plaintiff seeks declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by the Managing General Partner pursuant to leases. The Managing General Partner moved the case to Federal Court on June 28, 2007, and on July 10, 2007, the Managing General Partner filed its answer and affirmative defenses.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

Notes to Financial Statements

On February 29, 2008, the court granted a 90 day stay in proceedings while parties pursue mediation of the matter. Given the preliminary stage of this proceeding and the inherent uncertainty in litigation, the Managing General Partner is unable to predict the ultimate outcome of the suit at this time.

Although at this time the Partnership has not been named as a party in the suit, the Managing General Partner believes that a majority of the Partnership’s 64 wells in the Wattenberg field will be subject to the lawsuit. Although the outcome of the suit cannot be known with certainty, we believe that we have adequately accrued liabilities and that the ultimate outcome of the proceedings will not have a material adverse impact on the Partnership’s financial position or results of operations.

F-19

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Avg

Rockies Region 2006 Limited Partnership 10-K2007 FY Annual report

Content analysis