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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2010

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

For the transition period from __________ to _________

Commission File Number 000-07246

PETROLEUM DEVELOPMENT CORPORATION

(Exact name of registrant as specified in its charter)

(Doing Business as PDC Energy)


Nevada	95-2636730
(State of Incorporation)	(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000

Denver, Colorado 80203

(Address of principal executive offices) (Zip Code)

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

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


Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share		NASDAQ Global Select Market

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £ No £

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer £	Accelerated filer x
Non-accelerated filer £ (Do not check if a smaller reporting company)	Smaller reporting company o

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

The aggregate market value of our common stock held by non-affiliates on June 30, 2010, was $489,660,892 (based on the then closing price of $25.62).

As of February 11, 2011, there were 23,463,272 shares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Form is incorporated by reference to our definitive proxy statement to be filed pursuant to Regulation 14A for our 2011 Annual Meeting of Shareholders.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

2010 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS


	PART I	Page

Items 1 and 2.	Business and Properties	4
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	27
Item 3.	Legal Proceedings	27
Item 4.	[Reserved]	27

	PART II

Item 5.	Market for the Registrant's Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	28
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	45
Item 8.	Financial Statements and Supplementary Data	48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	48
Item 9A.	Controls and Procedures	48
Item 9B.	Other Information	49

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	49
Item 11.	Executive Compensation	49
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	49
Item 13.	Certain Relationships and Related Transactions and Director Independence	49
Item 14.	Principal Accountant Fees and Services	49

	PART IV

Item15.	Exhibits, Financial Statement Schedules	49

	SIGNATURES	52

PART I

REFERENCES TO THE REGISTRANT

Unless the context otherwise requires, references to "PDC," "PDC Energy," "the Company," "we," "us," "our," "ours" or "ourselves" in this report refer to the registrant, Petroleum Development Corporation and its consolidated entities. See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included in this report for a description of our consolidated entities.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the United States ("U.S.") Securities and Exchange Commission ("SEC"). Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.petd.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact Petroleum Development Corporation, Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call toll free (800) 624-3821.

We recommend that you view our web site for additional information, as we routinely post information that we believe is important for investors. Our web site can be used to access such information as our recent news releases, bylaws, committee charters, code of business conduct and ethics, shareholder communication policy, director nomination procedures and our whistle-blower hotline. While we recommend that you view our web site, the information available on our web site is not part of this report and is not hereby incorporated by reference.

UNITS OF MEASUREMENT

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

Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume.

Bcf – One billion cubic feet of natural gas volume.

Bcfe – One billion cubic feet of natural gas equivalent.

Btu – British thermal unit.

BBtu - One billion British thermal units.

MBbls – One thousand barrels of crude oil.

Mcf – One thousand cubic feet of natural gas volume.

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

MMBtu – One million British thermal units.

MMcf – One million cubic feet of natural gas volume.

MMcfe – One million cubic feet of natural gas equivalent.

GLOSSARY OF INDUSTRY TERMS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.

Behind-pipe reserves - Natural gas and crude oil reserves, proved or unproved, that cannot be produced until future perforation of casing at the depth of that reservoir. Generally, these are reserves in reservoirs above currently producing zones.

CIG - Colorado Interstate Gas.

Completion - The installation of permanent equipment for the production of natural gas and crude oil.

Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

Exit rate - Natural gas equivalent produced as of the date specified.

Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest.

Fracturing - Procedure to stimulate production by forcing a mixture of fluid (usually water) and proppant (usually sand) into the formation under high pressure. Fracing creates artificial fractures in the reservoir rock to increase permeability and porosity.

Gross acres or wells - Refers to the total acres or wells in which we have a working interest.

Horizontal drilling - A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

Joint interest billing or JIB - Process of distributing the costs related to well completions and operations among working interest partners.

Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane, and natural gasolines.

Net acres or wells - Refers to gross acres or wells multiplied, in each case, by the percentage working interest we own.

Net production - Natural gas and crude oil production that we own, less royalties and production due to others.

NYMEX - New York Mercantile Exchange.

Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease.

PEPL - Panhandle Eastern Pipeline.

Proved developed non-producing reserves or PDNPs - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves.

Proved reserves - Those quantities of natural gas, NGL, crude oil and condensate, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion - The modification of an existing well for the purpose of producing natural gas and crude oil from a different producing formation.

Refrac or refracture - A refrac is when we stimulate the present producing zone of a well to increase its production as well as its PDPs, using hydraulic, acid, gravel, etc. fracture techniques.

Reserve replacement - Calculated by dividing the sum of reserve additions from all sources (revisions, extensions, discoveries and other additions and acquisitions) by the actual production for the corresponding period. The values used for reserve additions are derived directly from the proved reserves table located in Supplemental Information - Natural Gas and Crude Oil Operations to our consolidated financial statements included in this report. We use the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow our reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

Reserves - Estimated remaining quantities of natural gas and crude oil and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering natural gas and crude oil or related substances to market, and all permits and financing required to implement the project.

Royalty - An interest in a natural gas and crude oil lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure of discounted future net cash flows - Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense.

Trunk line - A pipeline for the transportation of natural gas or crude oil from producing areas to refineries or terminals.

Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and crude oil, regardless of whether such acreage contains proved reserves.

Wellbore - A physical hole that makes up the well, and can be cased, open or a combination of both.

Working interest - An interest in a natural gas and crude oil lease that gives the owner of the interest the right to drill and produce natural gas and crude oil on the leased acreage. It requires the owner to pay all of their share of the costs of drilling and production operations.

Workover - Major remedial operations on a producing well to restore, maintain or improve the well's production.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas, NGL and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and our management’s strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:


•	changes in production volumes, worldwide demand and commodity prices for natural gas and crude oil;


•	changes in estimates of proved reserves;


•	declines in the values of our natural gas and crude oil properties resulting in impairments;


•	the timing and extent of our success in discovering, acquiring, developing and producing reserves;


•	our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;


•	reductions in the borrowing base under our credit facility;


•	risks incident to the drilling and operation of natural gas and crude oil wells;


•	future production and development costs;


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


•	the effect of existing and future laws, governmental regulations and the political and economic climate of the U.S.;


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


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


•	our ability to insure adequately against operational mishaps and environment events;


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


•	the availability and cost of capital to us;


•	our ability to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all;


•	conditions in the capital markets; and


•	losses possible from pending or future litigation.

Further, we urge you to carefully review and consider the disclosures made in this report, including the risks and uncertainties that may affect our business as described herein under Item 1A, Risk Factors, and our other filings with the SEC. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

The Company

Established in 1969, we are an independent natural gas and crude oil company that explores for and acquires, develops, produces and markets natural gas and crude oil resources. Effective July 15, 2010, we began conducting business as PDC Energy. A new logo and corporate identity accompanied this change. Our common stock continues to trade on the NASDAQ Global Select Market under the ticker symbol PETD. Our web site, www.petd.com, reflects the new PDC Energy name and brand identity. We believe that the name PDC Energy more fully portrays the range of business activities in which we engage. At our annual shareholder meeting to be held in June 2011, we plan to request our shareholders to approve and amend our articles of incorporation to formally change our corporate name to PDC Energy.

2010 Overview

The year 2009 serves to remind us just how uncertain the commodity and financial markets can be and that our response to such uncertainty is crucial to our ability to achieve growth. We spent much of our efforts in 2009 ensuring that we had sufficient liquidity to weather the uncertain economic environment by maintaining a disciplined capital expenditure program. In 2010, as the economic environment began a slow but steady recovery, we increased our capital budget and were in an opportunistic position to be able to participate in certain growth opportunities presented. With capital markets showing renewed strength and confidence late in 2010, we took the opportunity to access the markets in November 2010 and successfully completed a $132.5 million sale of equity and a $115 million issuance of 3.25% convertible senior notes. Further in November 2010, we amended our bank credit facility, increasing our maximum facility amount and extending the maturity date to November 2015.

Our 2010 capital expenditures, exclusive of acquisitions, increased 13.8% over those in 2009. Because growth in production generally lags behind the investment, as evidenced by our decrease in production in 2010 as a result of our controlled investment in 2009, we believe that the consecutive increases in quarterly production experienced during the second half of 2010 signify our return to production growth.

In addition to our focus on organic growth, our business development group was actively pursuing available opportunities. In July, we successfully completed our first acquisition in the liquid producing province of the Permian Basin in West Texas. This acquisition was strategically important for two reasons: (1) it brought us closer to achieving our natural gas/crude oil production mix goal of 65/35 and (2) it allowed us to monetize our Michigan asset group while benefiting from Internal Revenue Code Section 1031, Like Kind Exchange, with the deferral of a $6.5 million tax liability. In November 2010, we completed our second acquisition in the Permian Basin, adding to our acreage holdings an additional 5,760 contiguous net undeveloped acres. Finally, in December 2010, we completed the acquisition of four affiliated partnerships. We believe that these partnership acquisitions will allow us the opportunity to grow through an accelerated refracturing program in our liquids-rich Wattenberg Field.

Business Strategy

Our primary objectives are to increase shareholder value through the growth of our reserves and production, while operating our properties in an efficient manner to maximize the cash flow and earnings potential of our assets. To achieve meaningful increases in these key areas, we maintain an active drilling and acquisition program that focuses on low risk development of our natural gas and crude oil reserves, targets emerging plays and enables us to acquire producing and undeveloped properties with what we believe to be significant development potential. In addition, we believe we maintain a conservative and disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy. Our exploration program seeks to explore in areas where we believe we have a competitive advantage through operational expertise and a low cost of entry.

Drill and Develop

Our acreage holdings consist primarily of interests in developed and undeveloped natural gas and crude oil leases with positions primarily in the Rocky Mountain Region, the Permian Basin in West Texas and, through our joint venture, PDC Mountaineer, LLC ("PDCM"), the Appalachian Basin. We seek to maximize the value of our existing wells through a program of well recompletions, refractures and workovers and believe that our holdings of undeveloped properties provide us with a number of substantial new drilling projects. For 2011, we have planned approximately 124 new gross developmental drilling projects in the Rocky Mountain Region, including 14 horizontal projects targeting the Horizontal Niobrara formation and 90 vertical projects targeting the Codell and Niobrara formations, 25 projects in the Permian Basin and 9 horizontal Marcellus projects in the Appalachian Basin. Further, we have planned approximately 140 recompletion and refracture opportunities in our Wattenberg Field.

Drilling Activities. Our primary focus in the Rocky Mountain Region is on developmental drilling in the Wattenberg Field, where we primarily produce from the Codell and Niobrara formations. In October 2010, we launched a horizontal drilling program in our Wattenberg Field targeting the liquid rich play of the Niobrara shale. We currently have two drilling rigs operating in the Wattenberg Field and one rig in the Piceance Basin, executing a natural gas project with a strong focus on cost control and reserve optimization. In the Permian

Basin, we currently are focusing on developmental drilling and plan to keep at least one drilling rig operating on such projects. During 2010, in the Appalachian Basin, PDCM drilled five horizontal Marcellus shale wells to total depth, with three of them currently producing to pipeline, and began drilling a sixth well.

The following table presents the wells drilled, by operating area, during the last three years, as well as our planned 2011 drilling activity.


	Planned	Year Ended December 31,
	2011	2010		2009		2008
	Gross	Gross	Net	Gross	Net	Gross	Net
Rocky Mountain Region
Wattenberg Field	104	171	134.4	82	65.2	149	122.7
Grand Valley Field	12	25	25.0	1	1.0	62	54.4
Other	12	2	0.5	9	5.0	100	88.7
Total Rocky Mountain Region	128	198	159.9	92	71.2	311	265.8
Permian Basin	25	6	5.0	—	—	—	—
Appalachian Basin	9	8	4.5	8	8.0	62	62.0
Other	6	1	0.7	—	—	6	5.6
Total wells planned/drilled	168	213	170.1	100	79.2	379	333.4

The following table presents our developmental and exploratory drilling activity for the last three years. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells spudded, turned in line and producing during the period. In-process wells represent wells that have been spudded, drilled and waiting to be fractured and/or for gas pipeline connection during the period.


	Gross Drilling Activity
	Year Ended December 31,
	2010			2009			2008
	Productive	In-Process (1)	Dry	Productive	In-Process (2)	Dry	Productive	In-Process (3)	Dry
Development Wells
Rocky Mountain Region	150	47	—	70	17	2	216	73	8
Permian Basin	—	6	—	—	—	—	—	—	—
Appalachian Basin	1	2	—	2	—	—	44	16	—
Total development wells	151	55	—	72	17	2	260	89	8
Exploratory Wells
Rocky Mountain Region	—	1	—	2	1	—	4	3	7
Appalachian Basin	5	—	—	5	1	—	—	2	—
Other	—	1	—	—	—	—	3	—	3
Total exploratory wells	5	2	—	7	2	—	7	5	10
Total drilling activity	156	57	—	79	19	2	267	94	18
Recompletions/refractures	40			32			125

__________


(1)	Of the 57 wells in process as of December 31, 2010, 20 were connected and turned in line by February 11, 2011.


(2)	Of the 19 wells in process as of December 31, 2009, all were connected and turned in line in 2010.


(3)	Of the 94 wells in process as of December 31, 2008, 81 were connected and turned in line in 2009 and 13 were shut-in and are awaiting completion of a pipeline.


	Net Drilling Activity
	Year Ended December 31,
	2010			2009			2008
	Productive	In-Process	Dry	Productive	In-Process	Dry	Productive	In-Process	Dry
Development Wells
Rocky Mountain Region	125.4	33.5	—	61.3	6.9	1.0	174.0	69.8	8.0
Permian Basin	—	5.0	—	—	—	—	—	—	—
Appalachian Basin	0.6	1.1	—	2.0	—	—	44.0	16.0	—
Total development wells	126.0	39.6	—	63.3	6.9	1.0	218.0	85.8	8.0
Exploratory Wells
Rocky Mountain Region	—	1.0	—	1.0	1.0	—	4.0	3.0	7.0
Appalachian Basin	2.8	—	—	5.0	1.0	—	—	2.0	—
Other	—	0.7	—	—	—	—	3.0	—	2.6
Total exploratory wells	2.8	1.7	—	6.0	2.0	—	7.0	5.0	9.6
Total drilling activity	128.8	41.3	—	69.3	8.9	1.0	225.0	90.8	17.6
Recompletions/refractures	29.3			30.6			106.9

Strategically Acquire

Our acquisition efforts focus on producing properties that have a significant undeveloped acreage component. When weighing potential acquisitions, we prefer properties that have value in producing wells, behind-pipe reserves and high quality undeveloped drilling locations. In late 2009 and early 2010, we completed a U.S. onshore basin study that analyzed new areas where we could bring our skills and capital to crude oil and liquid rich fields that we believe can help deliver higher margins with scale and predictable drilling results. We plan to acquire properties through either direct acquisitions of the assets or acquisitions of entities owning the assets. We may also divest non-core assets as we seek to optimize our property portfolio. During 2011 and 2012, we expect to focus our resources on identifying and acquiring properties that have a high liquids component relative to its overall content.

Acquisitions in the Permian Basin. In July 2010, we acquired from an unrelated party 72 producing wells and 120 crude oil drilling locations located in the Wolfberry Trend in the Permian Basin in West Texas for $74.9 million. In November 2010, we acquired from an unrelated party 100% of the interest in additional producing assets and undeveloped acreage for $39.4 million. This second acquisition consisted of a primarily contiguous 5,760 net acre block with 122 identified crude oil drilling locations, based on 40-acre spacing.

Partnership Purchase Plan. In 2010, we initiated a plan to purchase our affiliated partnerships. The acquisition of these partnerships will provide us with immediate growth in both production and proved reserves from assets with which we are familiar. We believe that these acquisitions will also allow us to realize operational benefits and cost synergies as well as the opportunity to identify, pursue and accelerate a refracture program of the wells acquired. Pursuant to the plan, the following activity occurred in 2010.


•	Acquisition of 2004 Partnerships. In December 2010, we acquired four affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership. We purchased these partnerships for the aggregate amount of $34.8 million. These purchases included assets located in our core Wattenberg and Grand Valley Fields.

•

Potential Acquisition of 2005 Partnerships. In November 2010, we announced that we were pursuing the purchase of three affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership. The special meetings whereby investor partners of the 2005 partnerships will have an opportunity to vote and approve the applicable merger agreements are currently scheduled for March 25, 2011. We expect that if the required approvals are received from the investor partners at the special meetings and various other closing conditions are satisfied, each of the mergers for the 2005 partnerships will close no later than March 31, 2011. If all three 2005 partnerships are acquired, we will pay up to an aggregate of approximately $43.3 million for the limited partnership units of these partnerships. The assets in these 2005 partnerships are located in our core Wattenberg and Grand Valley Fields.

Divestiture of Michigan Assets. In July 2010, we divested our Michigan assets, consisting of primarily natural gas properties, and related liabilities for net cash proceeds of $22 million. We realized a loss on the sale of $4.7 million in the form of an impairment charge. Following the sale to an unrelated party, we do not have significant continuing involvement in the operations of or cash flows from this asset group; accordingly, the results of operations related to the Michigan assets have been separately reported as discontinued operations in the consolidated financial statements included in this report.

North Dakota Assets Held for Sale. During the fourth quarter of 2010, we developed a plan to divest and began marketing for sale our North Dakota assets. The assets include producing wells, undeveloped leaseholds and related facilities primarily located in Burke County. The plan received board approval and is expected to occur within one year of approval. In December 2010, we executed a letter of intent with an unrelated third party, which provides for the sale of 100% of our North Dakota assets. On February 7, 2011, we executed a purchase and

sale agreement with the same unrelated party and we expect the transaction to close early March 2011. Following the sale to the unrelated party, we will not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the results of operations related to the North Dakota assets have been separately reported as discontinued operations in the consolidated financial statements included in this report.

Manage Operational and Financial Risk

Historically, we have concentrated on developmental drilling and geographical diversification to help reduce risk levels associated with natural gas and crude oil drilling, production and commodity markets. Currently, the majority of our proved reserves are located in the Rocky Mountain Region. However, we believe we benefit from operational diversity in the Rocky Mountain Region by maintaining significant activity and production in separate areas containing a balanced mix of natural gas and crude oil. These areas include our liquid rich Wattenberg Field, including the emerging Horizontal Niobrara crude oil play, located in the DJ Basin in north central Colorado and our Grand Valley gas field in the Piceance Basin in western Colorado. In addition, we recently entered the liquid-rich Permian Basin of West Texas where we are building a significant drilling inventory in the Wolfberry Trend. We regularly review opportunities to further diversify into other regions where we can apply our operational expertise. We believe developmental drilling will remain the foundation of our capital program because we believe it is less risky than exploratory drilling. Although we engage in limited exploratory drilling, we view our exploratory activities as having the potential to identify new development opportunities that provide long-term production and reserve growth. We believe our joint venture, PDCM, serves to mitigate the risks associated with exploring our Marcellus Shale acreage by sharing the cost of exploratory drilling activities with an investing partner.

We believe we maintain a conservative financial approach and proactively employ strategies to help reduce the risks associated with the oil and natural gas industry. We believe we maintain a conservative balance sheet, focusing on providing sufficient liquidity to execute our business strategy. In addition, we utilize commodity-based derivative instruments to manage a portion of our exposure to price volatility with regard to our natural gas and crude oil sales and natural gas marketing. We utilize both financial and physical derivative instruments. The financial instruments generally consist of floors, collars, swaps and basis swaps and consist of NYMEX, CIG and PEPL-based contracts. We may utilize derivatives based on other indices or markets where appropriate. The contracts economically provide price stability for committed and anticipated natural gas and crude oil sales and purchases, generally forecasted to occur within the next two to four-year period. Our policies prohibit the use of commodity derivatives for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. As of December 31, 2010, we had natural gas and crude oil derivative positions in place for 2011 covering 52.8% of our expected natural gas production and 51.3% of our expected crude oil production.

Riley Natural Gas ("RNG"), a wholly owned subsidiary, uses financial derivatives in its gas marketing operations to coordinate fixed purchases and sales. RNG also enters into back-to-back fixed-price physical purchases and sales contracts with counterparties. RNG does not always hedge the area basis risk for third party trades with back-to-back fixed price purchases and sales. We continue to evaluate the potential for reducing this risk by entering into derivative transactions. Further, we may choose to close out any portion of a derivative contract existing at any time, which may result in a realized gain or loss on that derivative transaction.

Business Segments

We divide our operating activities into two segments: natural gas and crude oil sales and natural gas marketing.

Natural Gas and Crude Oil Sales

Commodity sales. Our natural gas and crude oil sales segment primarily reflects revenues and expenses from the production and sale of natural gas, NGLs and crude oil. We sell our natural gas and NGLs to other gas marketers, utilities, industrial end-users and other wholesale gas purchasers. We generally sell the natural gas that we produce under contracts with indexed monthly pricing provisions. Virtually all of our contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline. We believe that the pricing provisions of our natural gas contracts are customary in the industry. We also enter into financial derivatives in order to reduce the impact of possible price volatility regarding the physical sales market. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations: Results of Operations – Commodity Price Risk Management, Net, Natural Gas and Crude Oil Derivative Activities and Note 4, Derivative Financial Instruments, to our consolidated financial statements included in this report.

Our wells in the Permian Basin and our Wattenberg Field produce crude oil and condensate as well as natural gas and NGLs. We do not refine any of our crude oil production. Our Wattenberg crude oil production is sold to purchasers at or near our wells under both short and long-term purchase contracts with monthly pricing provisions. Our Permian crude oil production is transported through our own and third party gathering systems and pipelines to move our crude oil from the wellhead to a purchaser-specified delivery point.

Well operations and pipeline services. In addition to commodity sales, our natural gas and crude oil sales segment includes revenues and expenses related to well operations and pipeline services. As of December 31, 2010, we had an interest in 5,048 wells. We are paid a monthly operating fee for the portion of each well we operate that is owned by others, including our sponsored partnerships. The fee is competitive with rates charged by other operators in the area. As we are successful in our partnership acquisition program, revenues related to well operations and pipeline services will decrease.

We develop, own and operate gathering systems in some of our areas of operations. Pipelines and related facilities can represent a significant portion of the capital costs of developing wells, particularly in new areas located at a distance from existing pipelines. We consider these costs in our evaluation of our leasing, development and acquisition opportunities.

Our natural gas, NGLs and crude oil are transported through our own and third party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas transporters. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our gas before we can transport it. We typically contract with third parties in the Grand Valley and NECO areas of our Rocky Mountain Region and Appalachian Basin for firm transportation of our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline capacity. These agreements are subject to the same limitations discussed above in this paragraph. See Note 11, Commitments and Contingencies - Firm Transportation Agreements, to our consolidated financial statements included in this report for our long-term firm sales, processing and transportation agreements for pipeline capacity.

See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, Summary Operating Results, for production, sales, prices and lifting cost data for each of the years in the three-year period ended December 31, 2010.

Natural Gas Marketing

Our natural gas marketing segment is comprised of RNG. RNG specializes in the purchase, aggregation and sale of natural gas production in our Appalachian Basin. RNG purchases for resale natural gas produced by third party producers as well as natural gas produced by us, PDCM and our affiliated partnerships. The gas is marketed to third party marketers, natural gas utilities, as well as industrial and commercial customers, either directly through our gathering system, or through transportation services provided by regulated interstate pipeline companies.

For additional information regarding our business segments, see Note 17, Business Segments, to our consolidated financial statements included in this report.

Areas of Operations

The following map presents the general locations of our development, production and exploration activities as of December 31, 2010. We focus our development, production and exploration efforts primarily in three geographic areas of the U.S.: the Rocky Mountain Region, the Permian Basin of West Texas and, through our joint venture, the Appalachian Basin.

Rocky Mountain Region

Our primary focus in the Rocky Mountain Region is on developmental drilling. We divide our Rocky Mountain Region into two major operating areas: the Wattenberg and Grand Valley Fields.

•

Wattenberg Field, DJ Basin, Weld County, Colorado. Wells drilled in this area have historically been vertical and range from approximately 7,000 to 8,000 feet in depth. These wells targeted reservoirs in the Codell and Niobrara formations that have historically contained about 50% crude oil and NGLs. In October 2010, we began a horizontal drilling program targeting the liquid rich play of the Niobrara shale. Operations in the area, in addition to developmental drilling, include a program of refracturing existing wells in the Codell and Niobrara reservoirs. Well spacing ranges from 20 to 40 acres per well.

•

Grand Valley Field, Piceance Basin, Garfield County, Colorado. The majority of the development wells drilled in this area are drilled directionally from multi-well pads and generally range from two to ten wells per drilling pad. Wells range from 7,000 to 9,500 feet in depth and primarily target natural gas reserves developed from multiple sandstone reservoirs in the Mesaverde Williams Fork formation. Well spacing is approximately ten acres per well.

Permian Basin

We entered the Permian Basin through an acquisition in July 2010 and further added to our position in November 2010. Operating activities in this area focus on developmental drilling for crude oil from the Wolfberry Trend, which combines the Spraberry and Wolfcamp formations. Our Permian Basin assets also produce from additional long-life formations, including the Strawn, Fusselman and Ellenberger formations, where we have initiated production optimization and recompletion programs.

Appalachian Basin

In October 2009, through our contribution of the majority of our Appalachian Basin assets, consisting of acreage, producing properties and related reserves, gathering assets and equipment, and a cash contribution by Lime Rock Partners, LP, we formed the joint venture PDCM. The producing properties we contributed included developmental wells producing from the shallow Devonian and Mississippian aged tight sandstone reservoirs. PDCM focuses primarily on exploratory drilling, targeting the Marcellus Shale formation in West Virginia. In 2010, through our joint venture, we drilled five horizontal Marcellus Shale wells to total depth, with three of them currently producing to pipeline, and began drilling a sixth well.

In addition to wells owned through our joint venture, we own an interest in approximately 271 gross, 88.5 net, natural gas and crude oil wells in West Virginia, Pennsylvania and Tennessee.

Properties

Productive Wells

The table below presents our productive wells by operating area at December 31, 2010.


	Productive Wells
	As of December 31, 2010
	Natural Gas		Crude Oil		Total
Location	Gross	Net	Gross	Net	Gross	Net
Rocky Mountain Region
Wattenberg Field	1,627	1,175.3	25	19.3	1,652	1,194.6
Grand Valley Field	331	231.7	—	—	331	231.7
Other	717	501.8	12	4.4	729	506.2
Total Rocky Mountain Region	2,675	1,908.8	37	23.7	2,712	1,932.5
Permian Basin	—	—	74	71.4	74	71.4
Appalachian Basin	2,217	965.4	39	15.5	2,256	980.9
Other	6	5.7	—	—	6	5.7
Total productive wells	4,898	2,879.9	150	110.6	5,048	2,990.5

Proved Reserves

All of our proved reserves are located in the U.S. Our reserve estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and subsequent SEC staff regulations, interpretations and guidance. Substantially all of our proved reserves, including reserves held by consolidated companies and our proportionate share of PDCM and our affiliated partnerships, have been estimated by independent engineers. For our Appalachian Basin reserves, our internal reserve engineers estimated approximately three percent of the total proved developed natural gas reserves and approximately one percent of total proved undeveloped natural gas reserves.

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

Our reserve estimates as of December 31, 2010, were substantially based on reserve reports prepared by Ryder Scott Company, L.P. ("Ryder Scott"); approximately three percent of the total proved developed natural gas reserves and approximately one percent of total proved undeveloped natural gas reserves were based on reserve estimates prepared by our internal engineering team. For each of the years in the two-year period ended December 31, 2009, our reserve estimates for the Rocky Mountain Region and Fort Worth Basin were prepared by Ryder Scott and our reserve estimates for the Appalachian and Michigan Basins were based on reserve reports prepared by Wright & Company. When preparing our reserve estimates, the independent engineers did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices, or any agreements relating to current and future operations of properties and sales of production.

The independent petroleum engineers prepare an estimate of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined by acceptable industry methods and to a level of detail we deem appropriate. The final independent petroleum engineers' estimated reserve reports are reviewed and approved by our engineering staff and management.

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

The tables below present information regarding our estimated proved reserves. Reserves cannot be measured exactly, because reserve estimates involve judgments. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the Natural Gas and Crude Oil Information section of the supplemental information provided with our consolidated financial statements included in this report.


	As of December 31,
	2010		2009		2008
Proved reserves
Natural gas (MMcf)	657,306		608,925		662,857
Crude Oil, Condensate and NGLs (MBbls) (1)	33,885		18,070		15,037
Total proved reserves (MMcfe)	860,616		717,345		753,079
Proved developed reserves (MMcfe)	301,141		295,839		329,669
Estimated future net cash flows (in thousands) (2)	$	1,314,642	$	764,111	$	1,056,890
Standardized measure (in thousands) (2)(3)	$	488,418	$	347,636	$	356,805

______________


(1)	Prior to 2010, NGLs were included in natural gas, which impacts comparability for 2010 to 2009 and 2008. In 2010, NGLs represented 7.4% of total proved reserves.


(2)	Estimated future net cash flow represents the undiscounted estimated future gross revenue to be generated from the production of proved reserves, net of estimated production costs, future development costs and income tax expense. Prices used to estimate future gross revenues and production and development costs were based on the following:


•	Gross revenues


•	For 2010 and 2009, a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December; for 2008, prices in effect as of December 31, 2008.


•	Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity hedges.


•	Production and development costs


•	Prices as of December 31 for each of the respective years presented.


•	The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service, or to depreciation, depletion and amortization expense.


(3)	The standardized measure of discounted future net cash flow represents the present value of estimated future net cash flows discounted at a rate of 10% per annum to reflect timing of future cash flows.


	As of December 31, 2010
	Natural Gas (MMcf)	Crude Oil, Condensate and NGLs (MBbls)	Natural Gas Equivalent (MMcfe)	Percent
Proved developed
Rocky Mountain Region
Wattenberg Field	52,487	10,298	114,275	38	%
Grand Valley Field	106,260	244	107,724	36	%
Other	35,525	287	37,247	12	%
Total Rocky Mountain Region	194,272	10,829	259,246	86	%
Permian Basin	2,854	1,427	11,416	4	%
Appalachian Basin	30,081	44	30,345	10	%
Other	134	—	134	—	%
Total proved developed	227,341	12,300	301,141	100	%
Proved undeveloped
Rocky Mountain Region
Wattenberg Field	79,259	18,187	188,381	34	%
Grand Valley Field	304,343	304	306,167	55	%
Other	9,058	—	9,058	1	%
Total Rocky Mountain Region	392,660	18,491	503,606	90	%
Permian Basin	2,125	3,094	20,689	4	%
Appalachian Basin	35,180	—	35,180	6	%
Total proved undeveloped	429,965	21,585	559,475	100	%
Proved reserves
Rocky Mountain Region
Wattenberg Field	131,746	28,485	302,656	35	%
Grand Valley Field (1)	410,603	548	413,891	48	%
Other	44,583	287	46,305	5	%
Total Rocky Mountain Region	586,932	29,320	762,852	88	%
Permian Basin	4,979	4,521	32,105	4	%
Appalachian Basin	65,261	44	65,525	8	%
Other	134	—	134	—	%
Total proved reserves	657,306	33,885	860,616	100	%

______________


(1)	Two leases in our Grand Valley Field represent 48% of our total proved reserves.

Substantially all of our natural gas and crude oil properties, exclusive of properties held by PDCM, have been mortgaged or pledged as security for our credit facility. Substantially all of PDCM's properties have been pledged as collateral for the joint venture's credit facility. See Note 4, Derivative Financial Instruments, and Note 8, Long-Term Debt, to our consolidated financial statements included in this report.

Developed and Undeveloped Acreage

The following table presents, by operating area, leased acres as of December 31, 2010.


	As of December 31, 2010
	Developed		Undeveloped (1)		Total
Location	Gross	Net	Gross	Net	Gross	Net
Rocky Mountain Region
Wattenberg Field	49,900	48,300	33,600	25,200	83,500	73,500
Grand Valley Field	2,900	2,900	5,100	5,100	8,000	8,000
Other	32,520	24,400	164,400	107,700	196,920	132,100
Total Rocky Mountain Region	85,320	75,600	203,100	138,000	288,420	213,600
Permian Basin	6,900	6,400	6,600	6,400	13,500	12,800
Appalachian Basin	53,900	53,200	9,500	8,600	63,400	61,800
Other	400	400	17,300	14,100	17,700	14,500
Total acreage	146,520	135,600	236,500	167,100	383,020	302,700

__________

(1)

Substantially all of our undeveloped acreage is related to leaseholds that are held by production. We have no material acreage with near term expiry, with the exception of 5,800 gross, 5,500 net, acres located in the Permian Basin, which expire during 2011. We have initiated a continuous drilling program in accordance with the terms of the leases, which will allow us to establish and hold by production those properties deemed prospective for commercial development.

Title to Properties

We believe that we hold good and defensible title to our developed properties, in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary 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 remedial work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties.

The properties we own 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, including items such as operating agreements, current taxes, development obligations under natural gas and crude oil leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with the use of the properties.

Facilities

We lease 39,720 square feet in downtown Denver, Colorado, which serves as our corporate offices, through December 2015. We own a 32,000 square feet administrative office building located in Bridgeport, West Virginia, where we also lease approximately 17,700 square feet of office space in a second building through October 2011.

We own or lease field operating facilities in the following locations:


•	Colorado: Evans, Parachute and Wray


•	Pennsylvania: Indiana and Mahaffey


•	Texas: Midland


•	West Virginia: Bridgeport and Glenville

Governmental Regulation

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

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


•	bond requirements in order to drill or operate wells;


•	the location of wells;


•	the method of drilling and casing wells;


•	the surface use and restoration of well properties;


•	the plugging and abandoning of wells; and


•	the disposal of fluids.

Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary

pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws may establish maximum rates of production from natural gas and crude oil wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. Where wells are to be drilled on state or federal leases, additional regulations and conditions may apply. The effect of these regulations may limit the amount of natural gas and crude oil we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our natural gas and crude oil wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations.

Although we currently hold very little acreage under federal leases, if we wish to increase such holdings then our costs and timing will be increased due to the new Bureau of Land Management leasing policies announced in May 2010. These policies change, among other things, the required environmental review, including additional public input related to the proposed leases.

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

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

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


•	costs of providing service, including depreciation expense;


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


•	volume throughput assumptions.

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

Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. The industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. 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.

Environmental Matters

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

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.

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

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

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

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

Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including us, to procure and implement Spill Prevention, Control and Counter-measures plans relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990, or OPA, subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. We are also subject to the CWA and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release of petroleum or its derivatives into surface waters or into the ground. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil also enhances our risks related to soil and water contamination.

In 2009, the State of Colorado’s Oil and Gas Conservation Commission implemented new broad-based environmental and wildlife protection regulations for the industry. These regulations will continue to increase our costs and may ultimately limit some drilling locations. Our expenses relating to preserving the environment have risen over the past few years and are expected to continue to rise in 2011 and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See Note 11, Commitments and Contingencies – Litigation, Colorado Stormwater Permit, to our consolidated financial statements included in this report.

Operating Hazards and Insurance

Our exploration and production operations include a variety of operating risks, including, but not limited to, 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 natural gas. The occurrence of any of these could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our pipeline, gathering and distribution operations are

subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

Any significant problems related to 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.

Competition

We believe that our exploration, drilling and production capabilities and the experience of our management and professional staff generally enable us to compete effectively. We encounter competition from numerous other natural gas and crude oil companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing natural gas and crude oil and obtaining desirable natural gas and crude oil leases on producing properties. Many of these competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to explore for natural gas and crude oil prospects and to acquire additional properties in the future depends upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We also face intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic natural gas and crude oil exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties may increase in the future.

In 2010, certain regions experienced strong demand for drilling services and supplies which resulted in increasing costs. Our Wattenberg Field, Permian Basin and especially our Appalachian Basin experienced intense competition to gain access to drilling and pumping services. For 2011, early signs indicate increased costs are likely, in particular in our Wattenberg Field. Factors affecting competition in the industry include price, location of drilling, availability of drilling prospects and drilling rigs, fracturing services, pipeline capacity, quality of production and volumes produced. We believe that we can compete effectively in the industry in each of the areas where we have operations. Nevertheless, our business, financial condition and results of operations could be materially adversely affected by competition. We also compete with other natural gas and crude oil companies as well as companies in other industries for the capital we need to conduct our operations. With all the turmoil in the 2008/2009 capital markets, financing was more expensive and more difficult to obtain. If we do not have adequate capital to execute our business plan, we may be forced to curtail our drilling and acquisition activities.

Employees

As of December 31, 2010, we had 327 employees, including 195 in production, 8 in natural gas marketing, 30 in exploration and development, 72 in finance, accounting and data processing and 22 in administration. Our employees are not covered by a collective bargaining agreement. We consider relations with our employees to be very good.

Our engineers, supervisors and well tenders are responsible for the day-to-day operation of wells and some pipeline systems. Much of the work associated with drilling, completing and connecting wells, including fracturing, logging and pipeline construction, is performed under our direction by subcontractors specializing in these activities as is common in the industry.

ITEM 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities.

Risks Related to the Domestic and Global Economic Environment

The current slow economic growth both domestically and globally may not improve or there may be a reoccurrence of the recent global economic recession, which increases the magnitude and the likelihood of the occurrence of the negative consequences discussed in many of the risks factors that follow.

In particular, consider the risks related to (1) the rapid deterioration of demand for natural gas and crude oil resulting from such economic environment and the related negative effects on natural gas and crude oil pricing, and (2) the effect of the credit constraints on our business, including the severe reduction in the availability of credit for drilling or to finance acquisitions. Also consider the interplay between these two risks: decline in natural gas and crude oil prices can lead to a reduction in the borrowing base for our credit line, and hence a reduction in our credit available for drilling. Similarly, further reductions in natural gas and crude oil prices could result in some of our assets becoming uneconomic to exploit, which would reduce our reserves, which in turn would reduce our borrowing base and the credit available

to us. These factors could result in less drilling and production by us, and could thereby adversely affect our profitability and could limit our ability to execute our business plan. These factors could also make it impossible or extremely expensive to extend the term of our revolving credit line. The global economic environment also increases the potential of counterparty failure risk for both the banks which are parties to our natural gas and crude oil derivative holdings and for payments from purchasers of our natural gas and crude oil. Lastly, inability to ascertain the ultimate depth and duration of such economic environment could cause us to refrain from capital expenditures in order to maintain higher liquidity; our uncertainty and caution could result in significantly reduced drilling and hence reduced future production, which in turn may result in reduced reserves, resulting in a reduced borrowing base and availability of funds from our credit facility. All these risks could have a significant adverse effect on our business and our financial results. Any deterioration in the domestic or global economic conditions will further amplify these risks.

The current slow economic growth both domestically and globally may not improve or there may be a reoccurrence of the disruptions during the recent recession in the global financial markets and the related economic environment may further decrease the demand for natural gas and crude oil and the prices of natural gas and crude oil, thereby limiting our future drilling and production, and thereby adversely affecting our financial condition and profitability.

The global financial market disruptions during the recent recession and the related economic environment resulted in a decrease in the demand for natural gas and crude oil and therefore lower natural gas and crude oil prices. For example, during the last six months of 2008, the prices for natural gas and crude oil decreased over 60% from the 2008 peak. If there is such an additional reduction in demand in the future, the continued production of gas may increase current oversupply and result in still lower gas prices. There is no certainty how long this low price environment would continue. We operate in a highly competitive industry, and certain competitors may have lower operating costs in such an environment. Furthermore, as a result of any such disruptions in the financial markets, it is possible that in future years we would not be able to borrow or otherwise raise sufficient funds to sustain or increase capital expenditures. Such market conditions may also make it more difficult or impossible for us to finance acquisitions, through either equity or debt; acquisitions have historically been a major source of growth for us. Consequently, we would be unable to expand our reserves, drilling operations and production. We may also have difficulty finding partners to develop new drilling prospects and to build the pipeline systems needed to transport our gas. Inability of third parties to finance and build additional pipelines out of the Rockies, the Marcellus and elsewhere could cause significant negative pricing effects. Any of the above factors could adversely affect our operating results.

Risks Related to Our Business and the Industry

Natural gas and crude oil prices fluctuate unpredictably and a decline in natural gas and crude oil prices can significantly affect the value of our assets, our financial results and impede our growth.

Our revenue, profitability and cash flow depend in large part upon the prices and demand for natural gas and crude oil. The markets for these commodities are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. For instance, in much of 2010, natural gas prices were too low to economically justify many drilling operations. Changes in natural gas and crude oil prices have a significant effect on our cash flow and on the value of our reserves, which can in turn reduce our borrowing base under our senior credit facility Prices for natural gas and crude oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and crude oil, market uncertainty and a variety of additional factors that are beyond our control, including national and international economic and political factors and federal and state legislation. For example, any significant reduction in the growth rate of China could affect global oil prices significantly.

The prices of natural gas and crude oil are volatile, often fluctuating greatly. Lower natural gas and crude oil prices may not only reduce our revenues, but also may reduce the amount of natural gas and crude oil that we can produce economically. As a result, we may have to make substantial additional downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write-down operating assets to fair value, as a non-cash charge to earnings. We assess impairment of capitalized costs of proved natural gas and crude oil 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 may be sold. In 2010, in conjunction with our decision to divest our Michigan assets, we recorded a related impairment charge on proved natural gas and crude oil properties of $4.7 million and in 2008, we recorded impairment charges totaling $12.8 million, primarily related to our properties in the Fort Worth Basin and in North Dakota. We may incur impairment charges in the future, which could have a material adverse effect on the results of our operations.

A substantial part of our natural gas and crude oil production is located in the Rocky Mountain Region, making it vulnerable to risks associated with operating primarily in a single geographic area.

Our operations have been focused on the Rocky Mountain Region, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, 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 crude 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. For example, the recent increase in activity in the Niobrara could lead to bottlenecks in processing that negatively affect our results disproportionately compared to our more geographically diverse competitors.

Prior to 2010, natural gas prices in the Rocky Mountain Region often 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 are more likely to have a material adverse effect on our revenue, profitability and cash flow than those of our more geographically diverse competitors. Although current natural gas prices in the Rocky Mountain Region are not steeply discounted to NYMEX, there can be no assurance as to such continuation.

Our estimated natural gas and crude oil reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

Natural gas and crude oil reserve engineering requires subjective estimates of underground accumulations of natural gas and crude oil and assumptions concerning future natural gas and crude oil prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of natural gas and crude oil reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding future natural gas and crude oil prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect:


•	the estimates of reserves;


•	the economically recoverable quantities of natural gas and crude oil attributable to any particular group of properties;


•	future depreciation, depletion and amortization ("DD&A") rates and amounts;


•	impairments in the value of our assets;


•	the classifications of reserves based on risk of recovery;


•	estimates of the future net cash flows;


•	timing of our capital expenditures; and


•	the amount of funds available for us to utilize under our revolving credit facility.

Some of our reserve estimates must be made with limited production history, which renders these reserve estimates less reliable than estimates based on a longer production history. Numerous changes over time to the assumptions on which the reserve estimates are based, as described above, often result in the actual quantities of natural gas and crude oil recovered being different from earlier reserve estimates.

The present value of our estimated future net cash flows from proved reserves is not necessarily the same as the current market value of our estimated natural gas and crude oil reserves. The estimated discounted future net cash flows from proved reserves were based on the 12-month average natural gas and crude oil index prices. However, factors such as actual prices we receive for natural gas and crude oil and hedging instruments, the amount and timing of actual production, amount and timing of future development costs, supply of and demand for natural gas and crude oil, and changes in governmental regulations or taxation also affect our actual future net cash flows from our natural gas and crude oil properties.

The timing of both our production and incurrence of expenses in connection with the development and production of natural gas and crude oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our natural gas and crude oil properties or the industry in general.

Unless natural gas and crude oil reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations.

Producing natural gas and crude oil reservoirs generally is characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than we estimated and the rate can change due to other circumstances. Thus, our future natural gas and crude oil reserves and production and, therefore, our cash flow and income, are highly dependent on efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. As a result, our future operations, financial condition and results of operations would be adversely affected.

Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities.

Acquisitions of producing properties and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future natural gas and crude oil prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform engineering, geological and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited.

Our focus on acquiring producing natural gas and crude oil properties may increase our potential exposure to liabilities and costs for environmental and other problems existing on acquired properties. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an "as is" basis with no or limited remedies for breaches of representations and warranties. We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our acquisitions for which we have limited or no contractual remedies or insurance coverage.

Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. We acquire interests in wells which we may need to operate together with other partners, and we acquire pipelines that we may need to operate and expect we may need to commit to drilling in the acquired areas to achieve the expected benefits. Consequently, we may not be able to efficiently realize the assumed or expected economic benefits of properties that we acquire, if at all.

We may not be able to consummate additional prospective acquisitions of our drilling partnerships, which could adversely affect our business operations.

Consummation of future acquisitions of drilling partnerships, which is conditioned on a pricing agreement with the special committee of our board of directors, as well as customary closing conditions, which may not be satisfied or waived. In addition, consummation of the acquisition of partnerships requires approval by the holders of a majority of the limited partnership units held by the non-affiliated investors of each respective partnership. Furthermore, each of the partnerships must complete their SEC proxy disclosure review process and receive clearance from the SEC before the partnerships can request approval of the merger transactions from their non-affiliated investors. If we are unable to consummate all or a portion of these prospective acquisitions, we would not realize the expected benefits of the proposed acquisitions. In addition, we will have incurred, and will remain liable for, transaction costs, including legal, accounting, financial advisory and other costs relating to the prospective acquisitions, including the costs of the special committee of our board of directors, whether or not they are consummated. The occurrence of any of these events individually or in combination could have an adverse effect on our business, financial condition and results of operations.

Any acquisitions we complete, including the prospective acquisitions, are subject to substantial risks that could adversely affect our financial condition and results of operations.

Even if we complete the prospective acquisitions, integration of the prospective acquisitions may be difficult. Any acquisition involves potential risks, including, among other things:


•	the validity of our assumptions about reserves, future production, future commodity prices,

revenues, capital expenditures and operating costs, including synergies;


•	an inability to integrate the businesses we acquire successfully;


•	a decrease in our liquidity by using a portion of our available cash or borrowing capacity under

our revolving credit facility to finance acquisitions;


•	a significant increase in our interest expense or financial leverage if we incur additional debt to

finance acquisitions;


•	the assumption of unknown liabilities, losses or costs, including those that are environmental, for

which we are not indemnified or for which our indemnity is inadequate;


•	the diversion of management’s attention from other business concerns;


•	natural disasters;


•	the incurrence of other significant charges, such as impairment of natural gas and crude oil properties,

goodwill or other intangible assets, asset devaluation or restructuring charges;


•	unforeseen difficulties encountered in operating in new geographic areas; and


•	customer or key employee losses at the acquired businesses.

If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

When drilling prospects, we may not yield natural gas or crude oil in commercially viable quantities.

A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of natural gas or crude oil bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether natural gas or crude oil will be present or, if present, whether natural gas or crude oil will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. If a well is determined to be dry or uneconomic, which can occur even though it contains some natural gas or crude oil, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient natural gas and crude oil to be profitable. If we drill a dry hole or unprofitable well on current and future prospects, the profitability of our operations will decline and our value will likely be reduced. In sum, the cost of drilling, completing and operating any well is often uncertain and new wells may not be productive.

We may not be able to identify and acquire enough attractive prospects on a timely basis to meet our development needs, which could limit our future development opportunities and adversely affect our profitability.

Our geologists have identified a number of potential drilling locations on our existing acreage. These drilling locations must be replaced as they are drilled for us to continue to grow our reserves and production. Our ability to identify and acquire new drilling locations depends on a number of uncertainties, including the availability of capital, regulatory approvals, natural gas and crude oil prices, competition, costs, availability of drilling rigs, drilling results and the ability of our geologists to successfully identify potentially successful new areas to develop. Because of these uncertainties, our profitability and growth opportunities may be limited by the timely availability of new drilling locations. As a result, our operations and profitability could be adversely affected.

Drilling for and producing natural gas and crude oil are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and crude oil can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including:


•	unusual or unexpected geological formations;


•	pressures;


•	fires;


•	blowouts;


•	loss of drilling fluid circulation;


•	title problems;


•	facility or equipment malfunctions;


•	unexpected operational events;


•	shortages or delivery delays of equipment and services;


•	compliance with environmental and other governmental requirements; and


•	adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. We maintain insurance against various losses and liabilities arising from operations; however, insurance against all operational risks is not available. Additionally, our management may elect not to obtain insurance if the cost of available insurance is excessive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and the governmental response to an event could have a material adverse effect on our business activities, financial condition and results of operations.

Our hydrocarbon drilling, transportation and processing activities are subject to a range of applicable federal, state and local laws and regulations. A loss of containment of hydrocarbons during these activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. See Note 11, Commitments and Contingencies - Environmental, to our consolidated financial statements included in this report.

Under the "successful efforts" accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability.

We have conducted exploratory drilling and plan to continue exploratory drilling in 2011 in order to identify additional opportunities for future development. Under the "successful efforts" method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period when they are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed and have a negative effect on our debt covenants.

Increasing finding and development costs may impair our profitability.

In order to continue to grow and maintain our profitability, we must annually add new reserves that exceed our yearly production at a finding and development cost that yields an acceptable operating margin and DD&A rate. Without cost effective exploration, development or acquisition activities, our production, reserves and profitability will decline over time. Given the relative maturity of most natural gas and crude oil basins in North America and the high level of activity in the industry, the cost of finding new reserves through exploration and development operations has been increasing. The acquisition market for natural gas and crude oil properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values for crude

oil properties climbed in 2010 and these values may continue to increase in the future. This increase in finding and development costs results in higher DD&A rates. If the upward trend in crude oil finding and development costs continues, we will be exposed to an increased likelihood of a write-down in carrying value of our crude oil properties in response to any future falling commodity prices and reduced profitability of our operations.

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and crude oil reserves, and ultimately our profitability.

Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and crude oil reserves. To date, we have financed capital expenditures primarily with bank borrowings under our credit facility, cash generated by operations and capital markets, through the sale of equity and the issuance of debt securities. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including:


•	our proved reserves;


•	the amount of natural gas and crude oil we are able to produce from existing wells;


•	the prices at which natural gas and crude oil are sold;


•	the costs to produce natural gas and crude oil; and


•	our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our credit facility decreases as a result of lower natural gas and crude oil prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. There can be no assurance as to the availability or terms of any additional financing. Our inability to obtain additional financing, or sufficient financing on favorable terms, would adversely affect our financial condition and profitability.

If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower natural gas and crude oil prices, or we incur operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at planned levels, and our profitability may be adversely affected.

If additional capital is needed, we may not be able to obtain debt or equity financing on favorable terms, or at all. If cash generated by our operations or available under our revolving credit facility is not sufficient to meet our capital requirements, failure to obtain additional financing could result in a curtailment of the exploration and development of our prospects, which in turn could lead to a possible loss of properties, decline in natural gas and crude oil reserves and production and a decline in our profitability.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Seasonal weather conditions and lease stipulations designed to protect various wildlife affect natural gas and crude oil operations in the Rocky Mountains. In certain areas, including parts of the Piceance Basin in Colorado, drilling and other natural gas and crude oil activities are restricted or prohibited by lease stipulations, or prevented by weather conditions, for up to six months out of the year. This limits our operations in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability.

We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues.

We operate approximately 93% of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology.

Market conditions or operational impediments could hinder our access to natural gas and crude oil markets or delay production and thereby adversely affect our profitability.

Market conditions or the unavailability of satisfactory natural gas and crude oil transportation arrangements may hinder our access to natural gas and crude oil markets or delay our production. The availability of a ready market for natural gas and crude oil production depends on a number of factors, including the demand for and supply of natural gas and crude oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for the lack of a market or because of inadequacy, unavailability or the pricing

associated with natural gas pipelines, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until we made production arrangements to deliver the product to market. Thus, our profitability would be adversely affected.

Our derivative activities could result in financial losses or reduced income from failure to perform by our counterparties or could limit our potential gains from increases in prices.

We use derivatives for a portion of our natural gas and crude oil production from our own wells, our partnerships and for natural gas purchases and sales by our marketing subsidiary to achieve a more predictable cash flow, to reduce exposure to adverse fluctuations in the prices of natural gas and crude oil, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us 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 increases in the prices for natural gas and crude oil. They may also require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, 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. For instance, if natural gas and crude oil prices rise significantly, it could result in significant non-cash charges each quarter, which could have a material negative effect on our net income.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from our natural gas, NGL and crude oil sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our natural gas and crude oil derivatives as well as the derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers may adversely affect our financial condition and profitability.

Terrorist attacks or similar hostilities may adversely affect our results of operations.

Increasing terrorist attacks around the world have created many economic and political uncertainties, some of which may materially adversely affect our business. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly crude oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. The continuation of these attacks may subject our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects.

Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.

The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We do not carry contingent business interruption insurance related to the processing plants owned by our natural gas purchasers or oil refineries owned by our crude oil purchasers. For some risks, such as drilling blow-out insurance, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks that we are subject to are generally not fully insurable.

We may not be able to keep pace with technological developments in our industry.

Our industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, other natural gas and crude oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Competition in our industry is intense, which may adversely affect our ability to succeed.

Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce natural gas and crude oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas and crude oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. In addition, these

companies may have a greater ability to continue exploration activities during periods of low natural gas and crude oil market prices. Larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which can adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because many companies in our industry have greater financial and human resources, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and crude oil properties. These factors could adversely affect the success of our operations and our profitability.

Anti-oil and gas industry sentiment has increased. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our exploration, development, production and marketing 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 natural gas and crude oil wells. Under these laws and regulations, we 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 operations and subject us 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.

Part of the regulatory environment includes federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to the regulation of conservation practices and protection of correlative rights by state governments. These regulations affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and crude oil that we can produce and market. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals, drilling permits, 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 explore on or develop our properties. Additionally, the natural gas and crude oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff.

Illustrative of this trend are the regulations implemented in 2009 by the State of Colorado, which focus on the industry. These multi-faceted regulations significantly enhance requirements regarding natural gas and crude oil permitting, environmental requirements and wildlife protection. Permitting delays and increased costs could result from these final regulations.

The BP crude oil spill in the Gulf of Mexico and anti-industry sentiment may result in new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Although we have no operations in the Gulf of Mexico, this incident could result in regulatory initiatives in other areas as well that could limit our ability to drill wells and increase our costs of exploration and production. Furthermore, the U.S. Environmental Protection Agency ("EPA") has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, including public meetings around the country on this issue which have been well publicized and well attended. This renewed focus could lead to additional federal and state laws and regulations affecting our drilling, fracturing and operations. Additional laws, regulations or other changes could significantly reduce our future growth, increase our costs of operations, and reduce our cash flow, in addition to undermining the demand for the natural gas and crude oil we produce.

Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Pennsylvania. This could adversely affect the existing operations in these states and the economic viability of future drilling. Additional laws, regulations or other changes could significantly reduce our future growth, increase our costs of operations and reduce our cash flow, in addition to undermining the demand for the natural gas and crude oil we produce.

Certain federal income tax deductions currently available with respect to natural gas and crude oil and exploration and development may be eliminated as a result of future legislation.

In February 2009, U.S. President Barack Obama ("President Obama") and his administration (the "Obama administration"), released its budget proposals for the fiscal year 2010, which included numerous proposed tax changes. In April 2009, legislation was introduced to further these objectives, and in February 2010, the Obama administration released similar budget proposals for the fiscal year 2011. Although these proposals were not enacted, the changes contained in the budget proposals included the elimination of certain key U.S. federal income tax preferences currently available to natural gas and crude oil exploration and production. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for natural gas and crude oil properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could negatively affect our financial condition and results of operation.

New derivatives legislation and regulation could adversely affect our ability to hedge natural gas and crude oil prices and increase our costs and adversely affect our profitability.

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

•

The Dodd-Frank Act may decrease our ability to enter into hedging transactions which would expose us to additional risks related to commodity price volatility; commodity price decreases would then have an immediate significant adverse affect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.


•	We expect that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased counterparty costs, thereby increasing the costs of derivative instruments. Our derivatives counterparties may be subject to significant new capital, margin and business conduct requirements imposed as a result of the new legislation.

•

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


•	The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and crude oil that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In December 2009, the EPA, published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the Federal Clean Air Act. In June 2010, the EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration ("PSD"), and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions will be required to also reduce those emissions according to “best available control technology,” or BACT, standards. In its permitting guidance for greenhouse gases, issued on November 10, 2010, the EPA has recommended options for BACT, which include improved energy efficiency, among others. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also adversely affect demand for the natural gas and crude oil that we produce.

In addition, in October 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the U.S. on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. On November 8, 2010, the EPA finalized rules to expand its greenhouse gas reporting rule to include onshore natural gas and crude oil production, processing, transmission, storage and distribution facilities. Reporting of greenhouse gas emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 ("ACESA"), which would establish an economy-wide cap on emissions of greenhouse gases in the U.S. and would require most sources of greenhouse gas emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. By steadily reducing the number of available allowances over time, ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020, increasing up to an 83 percent reduction of such emissions by 2050. Many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The passage of legislation that limits emissions of greenhouse gases from our equipment and operations could require us to incur costs to reduce the greenhouse gas emissions from our operations, and it could also adversely affect demand for the natural gas and crude oil that we produce.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or increased costs for insurance.

Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate

that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the production of natural gas and crude oil, including from the development of shale plays. A decline in the drilling of new wells and related servicing activities caused by these initiatives could adversely affect our financial position, results of operations and cash flows.

Most of our drilling uses hydraulic fracturing. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the oil and natural gas industry in fracturing fluids under the federal Safe Drinking Water Act ("SDWA"), and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, Emergency Planning and Community Right-to-Know Act ("EPCRA"), or other laws. Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas and crude oil wells in shale, coalbed and tight sand formations. Sponsors of these bills, which are currently being considered in the legislative process, including the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. The Chairman of the House Energy and Commerce Committee has initiated an investigation of the potential impacts of hydraulic fracturing, which has involved seeking information about fracturing activities and chemicals from certain companies in the oil and natural gas sector. The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, including public meetings around the country on this issue which have been well publicized and well attended. In March 2010, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The initial results are expected in the fall of 2012.

Several states have also proposed additional disclosure concerning chemicals used in the process. New York has imposed a moratorium on hydraulic fracturing of horizontal wells pending additional environmental investigation by the state. Lawsuits have also been filed against unrelated third parties in Pennsylvania and New York alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to natural gas and crude oil production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or lead us to incur increased operating costs in the production of natural gas and crude oil, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and in related servicing activities, our profitability could be materially impacted.

Litigation against us pertaining to our royalty practices and payments is ongoing; our cost of defending these lawsuits, and any future similar lawsuits, could be significant and any resulting judgments against us could have a material adverse effect upon our financial condition.

In recent years, litigation has commenced against us and other companies in our industry regarding royalty practices and payments in jurisdictions where we conduct business. For more information on the suits that currently relate to us, see Note 11, Commitments and Contingencies, to our consolidated financial statements included in this report. We intend to defend ourselves vigorously in these cases. Even if the ultimate outcome of this litigation resulted in our dismissal, defense costs could be significant. These costs would be reflected in terms of dollar outlay as well as the amount of time, attention and other resources that our management would have to appropriate to the defense. Although we cannot predict an eventual outcome of this litigation, a judgment in favor of a plaintiff could have a material adverse effect on our financial condition and profitability.

Risks Associated with Our Indebtedness

Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations. Our lenders can unilaterally reduce our borrowing availability based on anticipated sustained natural gas and crude oil prices.

We depend on our revolving credit facility for future capital needs. The terms of the borrowing agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt financing could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable.

The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the natural gas and crude oil properties securing their loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and crude oil properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory

principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our credit facility could adversely affect our operations and our financial results.

The indentures governing our outstanding notes and our senior credit facility impose (and we anticipate that the indentures governing any other debt securities we may issue will also impose) restrictions on us that may limit the discretion of management in operating our business. That, in turn, could impair our ability to meet our obligations.

The indentures governing our outstanding notes and our senior credit facility contain (and we anticipate that the indentures governing any other debt securities we may issue will also contain) various restrictive covenants that limit management’s discretion in operating our business. In particular, these covenants limit our ability to, among other things:


•	incur additional debt;


•	make certain investments or pay dividends or distributions on our capital stock, or purchase, redeem or retire capital stock;


•	sell assets, including capital stock of our restricted subsidiaries;


•	restrict dividends or other payments by restricted subsidiaries;


•	create liens;


•	enter into transactions with affiliates; and


•	merge or consolidate with another company.

These covenants could materially and adversely affect our ability to finance our future operations or capital needs. Furthermore, they may restrict our ability to expand, to pursue our business strategies and otherwise conduct our business. Our ability to comply with these covenants may be affected by circumstances and events beyond our control, such as prevailing economic conditions and changes in regulations, and we cannot assure you that we will be able to comply with them. A breach of any of these covenants could result in a default under the indentures governing our outstanding senior notes and any other debt securities we may issue in the future and/or our senior credit facility. If there were an event of default under our indentures and/or the senior credit facility, the affected creditors could cause all amounts borrowed under these instruments to be due and payable immediately. Additionally, if we fail to repay indebtedness under our senior credit facility when it becomes due, the lenders under the senior credit facility could proceed against the assets which we have pledged to them as security. Our assets and cash flow might not be sufficient to repay our outstanding debt in the event of a default. The occurrence of such an event would adversely affect our operations and profitability.

Our senior credit facility also requires us to maintain specified financial ratios and satisfy certain financial tests. Our ability to maintain or meet such financial ratios and tests may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests, or that the lenders under the senior credit facility will waive any failure to meet such ratios or tests.

In addition, upon a change in control, we are required to offer to buy each senior note for 101% of the principal amount, plus unpaid interest. A change in control is defined to include: (i) when a majority of the Board of Directors are not continuing directors; (ii) when one person (or group of related persons) holds direct or indirect ownership of over 50% of our voting stock; or (iii) upon sale, transfer or lease of substantially all of our assets.

We may incur additional indebtedness to facilitate our acquisition of additional properties, which would increase our leverage and could negatively affect our business or financial condition.

Our business strategy includes the acquisition of additional properties that we believe would have a positive effect on our current business and operations. We expect to continue to pursue acquisitions of such properties and may incur additional indebtedness to finance the acquisitions. Our incurrence of additional indebtedness would increase our leverage and our interest expense, which could have a negative effect on our business or financial condition.

If we fail to obtain additional financing, we may be unable to refinance our existing debt, expand our current operations or acquire new businesses. This could result in our failure to grow in accordance with our plans, or could result in defaults in our obligations under our senior credit facility or the indentures relating to our outstanding senior notes.

In order to refinance indebtedness, expand existing operations and acquire additional businesses or properties, we will require substantial amounts of capital. There can be no assurance that financing, whether from equity or debt financings or other sources, will be available or, if available, will be on terms satisfactory to us. If we are unable to obtain such financing, we will be unable to acquire additional businesses or properties and may be unable to meet our obligations under our senior credit facility and the indentures relating to our outstanding senior notes or any other debt securities we may issue in the future. Such an event would adversely affect our operations and profitability.

Risks Associated with Our Joint Venture

PDC Mountaineer, LLC is dependent upon our equity partner (the “Investor”) and poses exit-related risks for us.

The board of managers of the joint venture consists of three representatives appointed by us and three representatives appointed by the Investor, each with equal voting power. The joint venture agreement generally requires the affirmative vote of a majority of the members of the board to approve an action, and we and the Investor may not always agree on the best course of action for the joint venture. If such a

disagreement were to occur, we would not be able to cause the joint venture to take action that we believed to be in the best interests of the joint venture. Consequently, our best interests may not be advanced and our investment in the joint venture could be adversely affected. If there is a disagreement about a development plan and budget for the joint venture, the Investor is entitled to unilaterally suspend substantially all of the operations of the joint venture, which could have a material adverse impact on the results of operations of the joint venture and our investment. Such a suspension could last for up to two years, at which point either party could elect to dissolve the joint venture or to sell their ownership interests to a third party. The Investor is entitled to a preference with respect to liquidating distributions and proceeds from significant sales of ownership interests up to the amount of its contributed capital, which would diminish our returns if the value of the joint venture had declined at the time of the liquidation or sale.

After a “restricted period” which generally lasts for the four year years following the closing of the joint venture, the Investor can seek to sell its interest in the joint venture to a third party, subject to rights of first offer and refusal in favor of us. If we do not exercise those rights in a sale involving all of the Investor’s ownership interests, the Investor can exercise “drag-along” rights and compel us to sell all of our interests in the proposed transaction. Accordingly, if we possessed insufficient funds and were unable to obtain financing necessary to purchase the Investor’s interest under the rights of first offer and refusal, we may be required to sell our interest in the joint venture at a time when we may not wish to do so. Under these circumstances, our investment in the joint venture could be adversely affected.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

Information regarding our legal proceedings can be found in Note 11, Commitments and Contingencies – Litigation, to our consolidated financial statements included in this report.

ITEM 4. [RESERVED]

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.01 per share. Our common stock is traded on the NASDAQ Global Select Market under the ticker symbol PETD. The following table presents the range of high and low sales prices for our common stock for each of the periods presented.


	Price Range
	High		Low

January 1 - March 31, 2009	$	27.91	$	9.39
April 1 - June 30, 2009	20.63		11.21
July 1 - September 30, 2009	19.14		12.50
October 1 - December 31, 2009	21.87		16.06
January 1 - March 31, 2010	25.37		18.11
April 1 - June 30, 2010	27.73		17.92
July 1 - September 30, 2010	30.39		23.82
October 1 - December 31, 2010	43.01		27.44

As of February 11, 2011, we had approximately 944 shareholders of record.

We have not paid any dividends on our common stock and currently intend to retain earnings for use in our business. We do not expect to declare cash dividends in the foreseeable future.

The following table presents information about our purchases of our common stock during the three months ended December 31, 2010.


Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs

October 1 - 31, 2010	724	$	31.26	—	—
November 1 - 30, 2010	3,207	34.57		—	—
December 1 - 31, 2010	1,474	42.25		—	—
Total fourth quarter purchases	5,405	36.22

__________


(1)	Purchases represent shares purchased pursuant to our stock-based compensation plans for payment of tax liabilities related to the vesting of securities.

SHAREHOLDER PERFORMANCE GRAPH

The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2010, with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 175 crude petroleum and natural gas companies. The results shown in the graph below are not necessarily indicative of future performance.

__________


(1)	The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2005, and in the S&P 500 Index and the SIC Index on the same date.

ITEM 6. SELECTED FINANCIAL DATA


	Year Ended December 31,
	2010		2009			2008		2007 (3)			2006 (3)
	(in thousands, except per share data and as noted)
Statement of Operations
Natural gas, NGL and crude oil sales	$	209,644	$	171,242		$	304,867	$	175,187		$	115,189
Commodity price risk management gain (loss), net (1)	59,891		(10,053		)	127,838		2,756			9,147
Total revenues	347,647		230,876			572,501		291,737			267,237
Income (loss) from continuing operations	6,921		(80,118		)	105,831		26,085			233,102

Earnings (loss) per share attributable to shareholders:
Net income (loss) attributable to shareholders - basic	$	0.32	$	(4.82	)	$	7.69	$	2.25		$	15.18
Net income (loss) attributable to shareholders - diluted	$	0.31	$	(4.82	)	$	7.63	$	2.24		$	15.11

Statement of Cash Flows
Net cash provided by operating activities	$	151,813	$	143,895		$	139,101	$	60,304		$	67,390
Capital expenditures	162,723		143,033			323,153		238,988			146,180
Acquisitions	158,051		—			—		255,661			18,512

Balance Sheet
Total assets	$	1,389,035	$	1,250,327		$	1,402,704	$	1,050,479		$	884,287
Working capital (deficit)	16,194		32,936			31,266		(50,212		)	29,180
Long-term debt	295,695		280,657			394,867		235,000			117,000
Equity	642,241		538,593			512,275		396,285			360,144

Production, Pricing, and Lifting Costs
Total production (Bcfe)	37.6		41.6			36.9		28.0			16.9
Average sales price (excluding gains/losses on derivatives) (per Mcfe)	$	5.67	$	4.19		$	8.37	$	6.26		$	6.80
Average sales price (including gains/losses on derivatives) (per Mcfe)	$	6.92	$	6.77		$	8.62	$	6.52		$	6.91
Average lifting cost (per Mcfe) (2)	$	1.11	$	0.81		$	1.08	$	0.90		$	0.76

Total proved reserves (Bcfe)	860.6		717.3			753.1		685.6			322.7

______________


(1)	See Note 4, Derivative Financial Instruments, to our consolidated financial statements included in this report.


(2)	Lifting costs represent lease operating expenses, excluding production taxes, on a per unit basis.


(3)	The years ended 2007 and 2006 do not present the effects of the divestitures of our Michigan and North Dakota assets as discontinued operations as the amounts related to these operations were immaterial to these years.

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

The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included in this report. Further, we encourage you to revisit Special Note Regarding Forward-Looking Statements on page 3 of this report.

Non-GAAP Financial Measures

We use "adjusted cash flow from operations," "adjusted net income (loss) attributable to shareholders" and "adjusted EBITDA," non-GAAP financial measures, for internal managerial purposes, when evaluating period-to-period comparisons and providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP. The non-GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-GAAP Financial Measures below for a detailed description of these measures as well as a reconciliation of each to the nearest U.S. GAAP measure.

2010 Overview

In 2010, we committed our efforts to strengthen the structure of our business, by building a foundation that will support our operations for future growth. Production from continuing operations decreased by 9.5% compared to 2009, including the impact on comparability due to the recognition of NGL volumes separately from natural gas, which lessens the year-over-year decrease. We experienced a decrease in quarter-over-quarter production during the first half of the year, but achieved production growth in the third and fourth quarters, which we expect will be the trend in 2011 and beyond. The decrease in production in 2010 was a result of our conservative capital spending program in 2009 due to the unstable financial and commodity markets. Despite the decrease in production, our natural gas, NGL and crude oil sales revenue increased by $38.4 million due to improved pricing and our initiatives to increase crude oil and NGL production as a percentage of total production. The increase in crude oil and NGL production was the result of our increased investment in organic growth, primarily in our liquid-rich Wattenberg Field, and our more recent acquisitions in liquid-rich acreage in the Permian Basin. Our total 2010 revenues were also favorably impacted by realized derivative gains related to natural gas and crude oil sales of $47.1 million, which effectively resulted in a net realized price of $6.92 per Mcfe.

We closed 2010 with available liquidity of $356.9 million compared to $238.2 million at the end of 2009. Available liquidity is comprised of cash, cash equivalents and funds available under our credit facility. Capital markets strengthened during 2010 and as such, in November 2010, we recognized an opportunity to access the markets and did so through the sale of equity and the issuance of convertible debt, raising $247.5 million in capital. With our strong liquidity position, 2011 will be a year of increased capital spending, focused on organic growth in the liquid-rich areas of our Wattenberg Field and the Permian Basin along with the proposed acquisitions of our affiliated partnerships. We believe that, combined with our investment in 2010, our capital budget will grow our production from continuing operations by 19% in 2011, excluding any future acquisitions, while increasing the liquids portion of our production as a percentage of our total production and thereby benefiting from the crude oil to natural gas price differential.

Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results from continuing operations. Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2010 to 2009 and 2008.


	Year Ended December 31,
										Change
	2010			2009			2008			2010-2009		2009-2008
	(dollars in thousands, except per unit data)
Production (1)
Natural gas (MMcf)	26,387.5			34,089.6			30,101.1			(22.6	)%	13.3	%
Crude oil (MBbls)	1,265.3			1,244.0			1,135.8			1.7	%	9.5	%
NGLs (MBbls)	601.2			—			—			*		*
Natural gas equivalent (MMcfe) (2)	37,586.6			41,553.4			36,915.6			(9.5	)%	12.6	%
Average MMcfe per day	103.0			113.8			100.9			(9.5	)%	12.9	%
Natural Gas, NGL and Crude Oil Sales
Natural gas	$	95,147		$	105,449		$	207,086		(9.8	)%	(49.1	)%
Crude oil	93,670			68,499			101,806			36.7	%	(32.7	)%
NGLs	24,079			—			—			*		*
Provision for underpayment of natural gas sales	(3,252		)	(2,706		)	(4,025		)	20.2	%	(32.8	)%
Total natural gas, NGL and crude oil sales	$	209,644		$	171,242		$	304,867		22.4	%	(43.8	)%

Realized Gain (Loss) on Derivatives, net (3)
Natural gas	$	40,024		$	89,464		$	12,632		(55.3	)%	*
Crude oil	7,071			17,881			(3,145		)	(60.5	)%	*
Total realized gain on derivatives, net	$	47,095		$	107,345		$	9,487		(56.1	)%	*

Average Sales Price (excluding gain/loss on derivatives)
Natural gas (per Mcf)	$	3.61		$	3.09		$	6.88		16.8	%	(55.1	)%
Crude oil (per Bbl)	74.03			55.07			89.64			34.4	%	(38.6	)%
NGLs (per Bbl)	40.05			—			—			*		*
Natural gas equivalent (per Mcfe)	5.67			4.19			8.37			35.3	%	(49.9	)%

Average Sales Price (including gain/loss on derivatives)
Natural gas (per Mcf)	$	5.12		$	5.72		$	7.30		(10.4	)%	(21.7	)%
Crude oil (per Bbl)	79.62			69.44			86.86			14.7	%	(20.1	)%
NGLs (per Bbl)	40.05			—			—			*		*
Natural gas equivalent (per Mcfe)	6.92			6.77			8.62			2.2	%	(21.5	)%

Average Lifting Cost (per Mcfe) (4)	$	1.11		$	0.81		$	1.08		37.0	%	(25.0	)%

Natural Gas Marketing (5)	$	1,056		$	1,977		$	942		(46.6	)%	109.9	%

Other Costs and Expenses
Exploration expense	$	20,266		$	18,177		$	31,783		11.5	%	(42.8	)%
Impairment of proved natural gas and crude oil properties	—			926			7,579			(100.0	)%	(87.8	)%
General and administrative expense	42,188			53,985			37,715			(21.9	)%	43.1	%
Depreciation, depletion and amortization	109,243			126,755			101,443			(13.8	)%	25.0	%

Interest Expense	$	33,250		$	37,208		$	28,132		(10.6	)%	32.3	%

* Percentage change is not meaningful or equal to or greater than 300%.

Amounts may not recalculate due to rounding.

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(1)	Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage interest we own.


(2)	Six Mcf of natural gas equals one Bbl of crude oil or NGL.


(3)	Represents realized derivative gains and losses related to natural gas and crude oil sales segment, which do not include realized derivative gains and losses related to natural gas marketing.


(4)	Represents lease operating expenses, exclusive of production taxes, on a per unit basis.


(5)	Represents sales from natural gas marketing, net of costs of natural gas marketing, including realized and unrealized derivative gains and losses related to natural gas marketing activities.

Natural Gas, NGL and Crude Oil Sales

The following tables present natural gas, NGL and crude oil production and average sales price by area. Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2010 to 2009 and 2008.


	Year Ended December 31,
				Change
Production	2010	2009	2008	2010-2009		2009-2008
Natural gas (MMcf)
Rocky Mountain Region	23,650.8	29,957.4	26,087.8	(21.1	)%	14.8	%
Permian Basin	148.5	—	—	*		*
Appalachian Basin (1)	2,526.0	4,010.5	3,902.2	(37.0	)%	2.8	%
Other	62.2	121.7	111.1	(48.9	)%	9.5	%
Total	26,387.5	34,089.6	30,101.1	(22.6	)%	13.3	%
Crude oil (MBbls)
Rocky Mountain Region	1,224.9	1,233.3	1,127.9	(0.7	)%	9.3	%
Permian Basin	34.0	—	—	*		*
Appalachian Basin (1)	5.9	9.6	6.6	(38.5	)%	45.5	%
Other	0.5	1.1	1.3	(54.5	)%	(15.4	)%
Total	1,265.3	1,244.0	1,135.8	1.7	%	9.5	%
NGLs (MBbls)
Rocky Mountain Region	561.1	—	—	*		*
Permian Basin	31.6	—	—	*		*
Other	8.5