Edgar Filing: PDC ENERGY, INC.

PDCE-10K-FY12

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, 2012

£ 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

PDC ENERGY, INC.

(Exact name of registrant as specified in its charter)



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 T No £

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 Website, 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 T 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 x	Accelerated filer o
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 Act). Yes £ No T

The aggregate market value of our common stock held by non-affiliates on June 30, 2012 was $735,547,944 (based on the then closing price of $24.52 per share).

As of February 8, 2013, there were 30,316,670 shares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2013 Annual Meeting of Stockholders.

PDC ENERGY, INC.

2012 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS



	PART I	Page

Items 1. and 2.	Business and Properties	2
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	31
Item 3.	Legal Proceedings	31
Item 4.	Mine Safety Disclosures	31

	PART II

Item 5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6.	Selected Financial Data	34
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	35
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55
Item 9A.	Controls and Procedures	55
Item 9B.	Other Information	55

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	56
Item 11.	Executive Compensation	56
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	56
Item 13.	Certain Relationships and Related Transactions, and Director Independence	56
Item 14.	Principal Accounting Fees and Services	56

	PART IV

Item15.	Exhibits, Financial Statement Schedule	56

	Signatures	60

	Glossary of Units of Measurements and Industry Terms	61

PART I

REFERENCES TO THE REGISTRANT

At our annual meeting of stockholders held on June 7, 2012, the stockholders approved a change of the Company's legal name from Petroleum Development Corporation to PDC Energy, Inc. Reflecting this change, on July 16, 2012, our common stock began trading on the NASDAQ Global Select Market under the ticker symbol "PDCE." Information contained on or linked to our website, www.pdce.com, is not part of this report and is not hereby incorporated by reference and should not be considered part of this report.

Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our," "ours" or "ourselves" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture currently owned 50% each by PDC and Lime Rock Partners, LP, formed for the purpose of exploring and developing the Marcellus Shale formation in the Appalachian Basin. Unless the context otherwise requires, references in this report to "Appalachian Basin" includes PDC's proportionate share of our affiliated partnerships' and the PDCM's assets, results of operations, cash flows and operating activities.

See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries.

GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS

Units of measurements and industry terms defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report, are set in boldface type the first time they appear.

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" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated natural gas, natural gas liquids (“NGLs”) and crude oil reserves; future production (including the components of such production), expenses, cash flows, margins and liquidity; anticipated capital projects, expenditures and opportunities, including drilling locations and downspacing potential; future exploration and development activities; availability of additional midstream facilities and services in the Wattenberg Field and timing of that availability; availability of sufficient funding for our capital program and sources of that funding; potential for infrastructure projects to improve our NGL pricing; our compliance with debt covenants and the renewal of a letter of credit under our revolving credit facility; adequacy of our insurance; the future effect of contracts, policies and procedures we believe to be customary; effectiveness of our derivative program in providing a degree of price stability; our future dividend policy; closing of, and expected proceeds from, our pending asset disposition; and our future strategies, plans and objectives.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect 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 known and unknown risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:


•	changes in production volumes and worldwide demand, including economic conditions that might impact demand;


•	volatility of commodity prices for natural gas, NGLs and crude oil;


•	the impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;


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


•	changes in estimates of proved reserves;


•	inaccuracy of reserve estimates and expected production rates;


•	potential for production decline rates from our wells to be greater than expected;


•	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;


•	timing and receipt of necessary regulatory permits;


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


•	our future cash flows, liquidity and financial condition;


•	competition in the oil and gas industry;


•	availability and cost of capital to us;


•	reductions in the borrowing base under our revolving credit facility;


•	availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production, particularly in the Wattenberg Field, and the impact of these facilities on the prices we receive for our production;


•	our success in marketing natural gas, NGLs and crude oil;


•	effect of natural gas and crude oil derivatives activities;


•	impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;


•	cost of pending or future litigation;


•	effect that acquisitions we may pursue have on our capital expenditures;


•	potential obstacles to completing our pending asset disposition or other transactions, in a timely manner or at all, and purchase price or other adjustments relating to those transactions that may be unfavorable to us;


•	our ability to retain or attract senior management and key technical employees; and


•	success of strategic plans, expectations and objectives for future operations of the Company.

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. 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. All forward-looking statements are qualified in their entirety by this cautionary statement.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

The Company

We are a domestic independent exploration and production company that acquires, develops, explores and produces natural gas, NGLs and crude oil with operations in the Western and Eastern regions of the United States. Our Western Operating Region is primarily focused on development in the Wattenberg Field in Colorado, particularly in the liquid-rich horizontal Niobrara and Codell plays. In our Eastern Operating Region, we are currently focused on development activity in the liquid-rich portion of the Utica Shale play in Ohio. We are also pursuing horizontal development in the Marcellus Shale in northern West Virginia through our 50% joint venture interest in PDCM. We own an interest in approximately 7,200 gross producing wells and maintained an average production rate of 135.6 MMcfe per day for the year ended December 31, 2012, which was comprised of 65.3% natural gas, 10.2% NGLs and 24.5% crude oil. This represents production growth of 10.2% from continuing operations as compared to the year ended December 31, 2011. As of December 31, 2012, we had approximately 1.2 Tcfe of proved reserves with a present value of future net revenues (“PV-10”) value, which is not a financial measure under Accounting Principles Generally Accepted in the United States of America (“U.S. GAAP”), of $1.7 billion, representing growth of 141 Bcfe and $359 million, respectively, relative to the totals as of December 31, 2011. The percentage of our proved reserves represented by NGLs and crude oil rose to 48% as of December 31, 2012, up from 34% as of December 31, 2011. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10% and a reconciliation of our PV-10% value to our standardized measure.

The increase in our estimated proved reserves and production is primarily attributable to liquid-rich horizontal drilling activities in the Wattenberg Field and our June 2012 acquisition of certain Wattenberg Field properties and related assets from affiliates of Merit Energy (the "Merit Acquisition") for $304.6 million, after certain post-closing adjustments. The acquired assets comprise approximately 29,800 net acres, after post-closing adjustments, located almost entirely in the core Wattenberg Field with significant overlay with our existing acreage position. We believe that the Merit Acquisition should provide us with an opportunity to continue our rapid growth in the Wattenberg Field and to substantially increase our oil and NGL production. We drilled 37 horizontal Niobrara and Codell wells, completed 160 refracture and recompletion projects and participated in 19 non-operated drilling projects in the Wattenberg Field in 2012.

In our Eastern Operating Region, we have acquired an estimated 45,000 net acres targeting the wet gas and crude oil windows of the Utica Shale in southeast Ohio. Our year-end 2012 proved reserves do not include reserves associated with our Utica Shale properties. We drilled and completed two horizontal Utica Shale wells in 2012, both of which are currently shut-in awaiting pipeline connections. We also drilled one vertical Utica Shale well and completed two vertical Utica test wells in 2012 for the primary purpose of providing engineering and geological data in support of the horizontal play. In addition, PDCM drilled three and completed six horizontal Marcellus wells and constructed various midstream projects in 2012.

The following table presents our historical proved reserve estimates as of December 31, 2012 based on a reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineering consulting firm:



	Proved Reserves at December 31, 2012
	Proved Reserves (Bcfe)	% of Total Proved Reserves		% Proved Developed		% Liquids		Proved Reserves to Production Ratio (in years)	Production (MMcfe)
Western
Wattenberg Field	893.5	77	%	41	%	62	%	33.4	26,748
Other	84.6	8	%	100	%	1	%	5.1	16,672
Total Western	978.1	85	%	46	%	56	%	22.5	43,420
Eastern
Appalachian Basin	178.8	15	%	23	%	—	%	28.9	6,192
Total Eastern	178.8	15	%	23	%	—	%	28.9	6,192
Total proved reserves	1,156.9	100	%	42	%	48	%	23.3	49,612

On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including derivatives, for aggregate cash consideration of approximately $200 million, subject to certain adjustments. As of December 31, 2012, total estimated proved reserves related to these assets were 84.6 Bcfe. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture. There can be no assurance we will be successful in closing such divestiture.

In addition to our oil and gas exploration and production activities, we engage in natural gas marketing through our subsidiary Riley Natural Gas (“RNG”).

Our Strengths

•

Multi-year project inventory targeting highly economic oil and NGL production growth. We have a significant operational presence in three key U.S. onshore basins and have identified a substantial inventory of approximately 4,100 gross capital projects across our assets. This inventory includes approximately 3,300 gross projects in the liquid-rich Wattenberg Field, of which approximately 1,400 are horizontal Niobrara and Codell proved and probable locations that we expect to be capable of providing liquid-rich production growth for the next several years at attractive rates of return based on current strip prices. Potential downspacing of future drill sites would provide the opportunity for additional locations. In the core area of the Wattenberg Field, we have achieved an average of 335 MBoe gross reserves per horizontal well, with approximately 75% liquids contribution. In the Appalachian Basin, we have approximately 600 gross Marcellus Shale drilling locations in inventory, of which approximately 360 gross wells in our core focus area would be expected to generate reserves of 5 to 7 Bcfe per well. In addition, our leasehold position in the emerging Utica Shale play is expected to provide approximately 200 horizontal drilling opportunities in liquid rich areas. With the development of the horizontal Niobrara and Codell and exploration and delineation of acreage in the Utica Shale, we are focused on transitioning our portfolio to a higher mix of oil and NGLs that we believe is capable of delivering higher margins and improved capital efficiencies.

•

Track record of reserve and production growth. Our proved reserves have grown from 323 Bcfe at December 31, 2006 to approximately 1.2 Tcfe at December 31, 2012, representing a compound annual growth rate (“CAGR”) of 23.7%. During the same time period, our proved crude oil and NGL reserves grew at a CAGR of 52.7%. Our annual production grew from 16.9 Bcfe in 2006 to 49.6 Bcfe in 2012 from continuing operations, representing a CAGR of 19.7%.

•

Horizontal drilling and completion experience. We have a proven track record of applying technical expertise toward developing unconventional resources through horizontal drilling, having drilled 108 Niobrara, Codell, Marcellus and Utica horizontal wells as of December 31, 2012. We have begun multi-well pad drilling to further optimize costs and enhance horizontal drilling efficiencies. Pad drilling enables us to streamline the transition to increased well density in the horizontal Niobrara and Codell plays. We have approximately 2,000 gross horizontal proved and probable locations in inventory from our Wattenberg and Marcellus positions. Our current leasehold position in the emerging Utica Shale play is expected to provide approximately 200 horizontal drilling opportunities in liquid-rich areas.

•

Significant operational control in our core areas. As a result of successfully executing our strategy over time of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately 89% of our oil and natural gas properties. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas.


•	Access to liquidity. As of December 31, 2012, we had $2.5 million of cash and cash equivalents and $396.1 million available for

borrowing under our revolving credit facility. We have no near-term debt maturities, although we periodically repay borrowings outstanding under our revolving credit facility. We actively hedge our future exposure to commodity price fluctuations by entering into oil and natural gas swaps and collars. We have hedged approximately 28.7 Bcf of our natural gas production for 2013 at an average minimum price of $4.15 per Mcf. We have hedged approximately 2,326 MBbls of our oil production in 2013 at an average minimum price of $88.75 per Bbl. As of December 31, 2012, the net fair value of all of our hedges was approximately $30.3 million.


•	Management experience and operational expertise. We have a management team with a proven track record of performance and a technical and operational staff with significant expertise in the basins in which we operate, particularly with horizontal well development activities.

Business Strategy

Our business strategy focuses on generating shareholder value through the organic growth of our reserves, production and cash flows in our high-value, liquid-rich horizontal drilling programs. We also engage in targeted exploratory drilling of unconventional resources and maintain an active acquisition program. We pursue various midstream, marketing and cost reduction initiatives designed to increase our per unit operating margins and maintain a conservative and disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy.

Drill and Develop

Our leasehold interests consist of developed and undeveloped natural gas, NGLs and crude oil resources located in our Western and Eastern Operating Regions. Based on our prior acreage holdings and recent acquisitions, we have identified a substantial inventory of approximately 4,100 gross capital projects for development primarily through horizontal drilling in high-return, liquid-rich plays, as well as refracture and recompletion opportunities.

Western Operating Region. Our primary focus in the liquid-rich Wattenberg Field is the horizontal Niobrara and Codell plays. We have begun multi-well pad drilling to further optimize costs and enhance horizontal drilling efficiencies in the Wattenberg Field. Pad drilling enables us to streamline the transition to increased well density in the horizontal Niobrara and Codell plays. We also maintain a vertical drilling inventory in the Niobrara and Codell formations. We currently estimate that we have 3,300 gross capital projects, which include over 1,400 gross proved and probable projects for the horizontal Niobrara and Codell. Depending upon commodity prices and the number of drilling rigs operating, we believe that this inventory of projects provides us with over 10 years of drilling activity.

Of our total capital budget of $324 million for 2013, approximately 75%, or $245 million, is expected to be spent on development activities, substantially all of which is expected to be invested in the Wattenberg Field for an expanded horizontal Niobrara and Codell drilling program and participation in various non-operated projects. We plan to run a two-rig program in the Wattenberg Field through the second quarter of the year and add a third rig during the third quarter. Under this drilling program, we expect to drill approximately 63 horizontal Niobrara or Codell wells in 2013.

Additionally, we operate natural gas assets in the Piceance Basin in western Colorado and in northeast Colorado ("NECO"), where we focused on production optimization and increasing operating margins in 2012. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus, pursuant to which we have agreed to sell our Piceance Basin, NECO and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including derivatives. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture. There can be no assurance we will be successful in closing such divestiture.

Eastern Operating Region. We continue to delineate and develop our leasehold position in the Utica Shale. To date, we have drilled two vertical test wells to collect geologic data and two horizontal wells to test the productivity of the acreage. We currently estimate we have approximately 200 gross projects for horizontal drilling in the Utica Shale. In 2013, we expect to devote approximately $53 million of our 2013 capital program primarily toward drilling and completion activity in the Utica Shale, where we plan to drill approximately five horizontal wells targeting the wet gas and crude oil windows of the play.

Our other focus in the Eastern Operating Region is on horizontal drilling in the Marcellus Shale in West Virginia. In 2012, PDCM completed a total of six gross (three net) horizontal wells and constructed various midstream assets to gather and compress its Marcellus gas. We currently estimate we have approximately 600 gross projects for horizontal drilling in the Marcellus Shale. PDCM expects to drill a total of 14 gross horizontal Marcellus wells in 2013.

Strategically acquire

We typically pursue the acquisition of assets that have a balance of value in producing wells, behind-pipe reserves and high-quality undeveloped drilling locations. In 2010, we began seeking liquid-rich properties with large undeveloped drilling upside where we believe we can utilize our operational abilities to add shareholder value. We have an experienced team of management, engineering and geosciences professionals who identify and evaluate acquisition opportunities.

In June 2012, we completed the Merit Acquisition for an aggregate purchase price of approximately $304.6 million, after certain post-closing adjustments. We financed the purchase with cash from the May 2012 offering of our common stock and a draw on our revolving credit

facility. The acquired assets comprise approximately 29,800 net acres, after post-closing adjustments, located almost entirely in the core Wattenberg Field and with significant overlay with our existing acreage position. Following the closing of the Merit Acquisition, our total position in the core Wattenberg Field is approximately 98,600 net acres.

During 2011 and 2012, we acquired approximately 45,000 net acres of Utica leaseholds, targeting the wet natural gas and crude oil windows of the Utica Shale play throughout southeastern Ohio, for a purchase price of approximately $92.3 million. As an early entrant into the development of the Utica Shale, we believe we have gained valuable experience and expertise in proactively addressing title and other issues associated with the development of the play.

In October 2011, PDCM acquired 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur”) from an unrelated third-party for $139.2 million. The acquisition included approximately 1,340 gross wells producing natural gas from the shallow Devonian Shale and Mississippian formations and all rights and depths to an estimated 100,000 net acres in West Virginia, of which 90,000 acres are prospective for the Marcellus Shale. Substantially all of the acreage acquired is held by production and is in close proximity to PDCM's existing properties. Pursuant to our joint venture interest in PDCM, our portion of the purchase price was $69.6 million and we hold a 50% interest in both the wells and acreage acquired.

In 2010, we initiated a plan to purchase our affiliated partnerships. As of December 31, 2012, we had acquired a total of 12 affiliated partnerships for an aggregate purchase price of $107.7 million. The acquisition of these partnerships have provided us with immediate growth in both production and proved reserves from assets in which we currently own an operated working interest.

Manage operational and financial risk

We focus on development drilling programs in resource plays that offer repeatable results capable of driving growth in reserves, production and cash flows. We regularly review acquisition opportunities in our core areas of operation as we believe we can extract additional value from such assets through production optimization, refractures and recompletions and development drilling. In addition, core acquisitions can potentially provide synergies that result in economies of scale from a combined position. While we believe development drilling will remain the foundation of our capital programs, we continue our disciplined approach to acquisitions and exploratory drilling, both of which have the potential to identify new development opportunities.

We believe we proactively employ strategies to help reduce the financial risks associated with the oil and gas industry. One such strategy is to maintain a balanced production mix of natural gas and liquids. Our Western Operating Region produces natural gas, NGLs and crude oil, with a production mix of approximately 60.5% natural gas to 39.5% liquids during 2012. We expect that the Merit Acquisition and our horizontal drilling program will allow us to substantially increase our crude oil and NGL production. While our legacy properties in the Eastern Operating Region primarily produce natural gas, our Ohio properties are prospective in the wet gas and crude oil windows of the Utica Shale. This strategy of a diversified commodity mix helps to mitigate the financial impact from a decline in the market price in any one of our commodities. In addition, we utilize commodity-based derivative instruments to manage a substantial portion of our exposure to price volatility with regard to our natural gas and crude oil sales and natural gas marketing. As of December 31, 2012, we had natural gas and crude oil derivative positions in place for 2013 covering approximately 28.7 Bcfe of our natural gas production and approximately 2,326 MBbls of our crude oil production. Currently, we do not hedge our NGL production. See Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for a detailed summary of our open derivative positions.

Selective exploration

We believe that our disciplined exploration program has the potential to consistently replenish our portfolio with new exploration projects capable of positioning us for significant production and reserve growth in future years. Due to the continued decline in natural gas prices, we have focused our efforts toward liquid-rich plays to take advantage of the current attractive economics associated with crude oil and NGL weighted projects. We strive to identify potential plays in their early stages in an attempt to accumulate significant leasehold positions prior to competitive forces driving up the cost of entry. We seek investment in leasehold positions that are in the proximity of existing or emerging pipeline infrastructures. We believe the leasehold we acquired targeting the Utica Shale meets these criteria and we see the derisking and delineation of this leasehold as our primary exploration focus during for 2013.

Business Segments

We divide our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing.

Oil and Gas Exploration and Production

Our Oil and Gas Exploration and Production segment primarily reflects revenues and expenses from the production and sale of natural gas, NGLs and crude oil.

•

Natural gas. We primarily sell our natural gas to midstream marketers, utilities, industrial end-users and other wholesale purchasers. We generally sell the natural gas that we produce under contracts with indexed or NYMEX monthly pricing provisions, with the remaining production sold under contracts with daily 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 and the quality of the natural gas. 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.


•	NGLs. The majority of our NGLs are sold to one NGL marketer in the Wattenberg Field. Our NGL production is sold under both short- and long-term purchase contracts with monthly pricing provisions based on an average daily price.


•	Crude oil. We do not refine any of our crude oil production. We sell our crude oil to oil marketers and refiners. Our crude oil production is sold to purchasers at or near our wells under both short- and long-term purchase contracts with monthly pricing provisions based on an average daily price.

We enter into financial derivatives in order to reduce the impact of possible price volatility regarding the physical sales market. See Part II, 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, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, and Note 4, Derivative Financial Instruments, to our consolidated financial statements included elsewhere in this report.

Our Oil and Gas Exploration and Production segment also reflects revenues and expenses related to well operations and pipeline services. We are paid a monthly operating fee for the portion of each well we operate that is owned by others, including our affiliated partnerships. We believe the fee is competitive with rates charged by other operators in the area. As we acquire the working interest of our non-affiliated investor partners in our affiliated partnerships, revenues related to well operations and pipeline services will decrease.

We construct, 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 the evaluation of our leasing, development and acquisition opportunities.

Our natural gas is transported through our own and third-party gathering systems and pipelines, and we incur gathering, processing and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based upon the volume and distance shipped, as well as the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally interrupted due to operational issues, repairs or improvements. A portion of our natural gas is transported under interruptible contracts and the remainder under firm transportation agreements, either directly with RNG or through third-party processors or marketers. Therefore, interruptions in natural gas sales could result if pipeline space is constrained. As discussed in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Operational Overview, our 2012 production was adversely affected by high line pressures experienced by our principal third-party provider of natural gas gathering, processing and transportation facilities in the Wattenberg Field. The high line pressure was the result of a series of operational issues and capacity constraints, primarily in the second and third quarters. The operational issues included downtime on downstream third-party NGL transportation and fractionation facilities and abnormally warm weather, which limited third-party gathering system compression capacity. We are working closely with our primary midstream provider who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity in the Wattenberg Field. However, we do not expect the impact of this increased capacity to substantially benefit us until late 2013. While our ability to market these volumes of natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our production and cash flows 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 natural gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our natural gas before we can transport it. We typically contract with third parties in the NECO area of our Western Operating Region and our Eastern Operating Region 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. See Note 11, Commitments and Contingencies - Firm Transportation Agreements, to our consolidated financial statements included elsewhere in this report for our long-term firm sales, processing and transportation agreements for pipeline capacity.

Our crude oil production is marketed directly to purchasers in the Wattenberg Field area under a combination of annual and short-term monthly agreements. The majority of our crude oil is delivered to local area refineries with other volumes being either trucked or shipped via pipeline out of the Wattenberg area.

See Part II, 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, 2012.

Gas Marketing

Our Gas Marketing segment is comprised solely of the operating activities of RNG. RNG specializes in the purchase, aggregation and sale of natural gas production in the Eastern Operating Region. 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 natural gas is marketed to third-party marketers, natural gas utilities and industrial and commercial customers, either directly through our gathering system or through transportation services provided by regulated interstate pipeline companies. Additionally, RNG markets our natural gas production in the NECO area.

For additional information regarding our business segments, see Note 18, Business Segments, to our consolidated financial statements included elsewhere in this report.

Areas of Operations

The following map presents the general locations of our development, production and exploration activities as of December 31, 2012. With the divestiture of our Permian Basin assets on February 28, 2012, our development, production and exploration efforts are primarily focused in two geographic areas of the U.S.

___________

(1) On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus, pursuant to which we have agreed to sell our Piceance Basin, NECO and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including derivatives. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture. There can be no assurance we will be successful in closing such divestiture.

Western Operating Region

Our primary focus in the Western Operating Region for 2013, and we expect for the next several years, is on horizontal Niobrara and Codell development drilling. We divide our Western Operating Region into the following areas:

•

Wattenberg Field, DJ Basin, Colorado. Currently, wells drilled in this area are horizontal wells targeting the liquid-rich reservoirs in the Codell and Niobrara formations. These horizontal wells have a vertical depth range from approximately 7,000 to 8,000 feet, with an average lateral length of 4,000 feet. We drill multi-well pads to further optimize costs and enhance horizontal drilling efficiencies in the Wattenberg Field. Pad drilling enables us to streamline the transition to increased well density in the horizontal Niobrara and Codell plays. We have approximately 3,300 gross projects, including over 1,400 proved and probable horizontal projects, in the liquid-rich Wattenberg Field.

In June 2012, we completed an acquisition of approximately 29,800 net acres in the core area, which positions us as the third largest producer and leaseholder in the core Wattenberg area. We estimate that the Wattenberg Field has approximately 400 horizontal drilling locations based on 4 gross wells per section for our proved undeveloped reserves ("PUDs"). Additional potential upside exists as we continue testing the Codell formation and plan to test downspacing to 10 gross wells per section in the play as part of our 2013 horizontal program, which is the basis for our estimate of over 1,400 horizontal wells in our proved and probable inventory.


•	Piceance Basin, Colorado. Wells in this area predominately target natural gas from the Williams Fork formation. For 2012, we removed all PUD reserves in the Piceance Basin due to low natural gas prices. Our 2012 Piceance natural gas reserves were 66.5 Bcfe, or approximately 6% of our total proved equivalent reserves. Our Piceance reserves represent approximately 2% of our

PV-10% as of December 31, 2012. See table in the Properties - Proved Reserves section below for information regarding our proved reserves and PV-10% as of December 31, 2012.

The majority of the wells drilled in this area are drilled directionally from multi-well drilling pads, generally range from two to ten wells per pad and range from 7,000 to 9,500 feet in depth. Reserves in this area originate from multiple sandstone reservoirs in the Mesaverde Williams Fork formation. Well spacing is approximately ten acres per well.


•	Northeastern Colorado. Wells drilled in this area range from 1,500 to 3,000 feet in depth and target natural gas reserves in the shallow Niobrara reservoir. Well spacing is approximately 40 acres per well.

As noted above, on February 4, 2013, we entered into a purchase and sale agreement with Caerus pursuant to which Caerus agreed to purchase our Piceance Basin, NECO and other non-core Colorado leasehold mineral interests and various other assets within these basins for an aggregate cash consideration of approximately $200 million, subject to post-closing adjustments. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence, and by certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus as part of the transaction. The effective date of the transaction is January 1, 2013. We intend to use the proceeds from the sale to repay a portion of amounts outstanding under our revolving credit facility and partially fund our 2013 capital program. There can be no assurance we will be successful in closing such divestiture.

Eastern Operating Region

Our primary focus in the Eastern Operating Region is on horizontal drilling in the Utica Shale in southeastern Ohio and the Marcellus Shale play in northern West Virginia.

•

Utica Shale, Ohio. We have acquired approximately 45,000 net acres targeting the wet natural gas and crude oil windows of the Utica Shale play throughout southeastern Ohio. To date, we have drilled and completed two horizontal wells in Guernsey County that are currently waiting on first production, as well as two stratigraphic vertical test wells to collect engineering and geologic data to test the productivity of the acreage. The horizontal wells have a vertical depth range of approximately 7,000 feet, with an average lateral length of 4,000 feet.

•

Marcellus Shale, West Virginia. Through our joint venture, PDCM, we have over 236,000 net acres in the Appalachian Basin, with approximately 152,000 acres prospective for the Marcellus Shale, the majority of which is in northern West Virginia. PDCM is primarily focused on horizontal drilling and has approximately 600 Marcellus Shale gross drilling locations on the West Virginia acreage. These wells have a vertical depth range from approximately 7,000 to 8,000 feet, with lateral lengths ranging from 4,000 to 6,000 feet.

In addition to our ownership interest in the wells held by PDCM, we own an interest in approximately 236 gross (77.9 net) natural gas and crude oil wells in West Virginia and Pennsylvania.

Properties

Productive Wells

The following table presents our productive wells:



	Productive Wells
	As of December 31, 2012
	Natural Gas		Crude Oil		Total
Operating Region/Area	Gross	Net	Gross	Net	Gross	Net
Western
Wattenberg Field	2,523	2,181.2	91	71.8	2,614	2,253.0
Other	1,057	800.7	—	—	1,057	800.7
Total Western	3,580	2,981.9	91	71.8	3,671	3,053.7
Eastern
Appalachian Basin	3,565	1,654.5	6	3.7	3,571	1,658.2
Total Eastern	3,565	1,654.5	6	3.7	3,571	1,658.2
Total productive wells	7,145	4,636.4	97	75.5	7,242	4,711.9

Proved Reserves

Our proved reserves are sensitive to future natural gas, NGLs and crude oil sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in commodity prices may result in negative impacts of this nature.

All of our proved reserves are located onshore 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. As of December 31, 2012, all of our proved reserves, including the reserves of all subsidiaries consolidated for the purposes of our financial statements, have been estimated by independent petroleum engineers.

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 process includes a review of applicable working and net revenue interests and cost and performance data. 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, 2012 were based on a reserve report prepared by Ryder Scott. When preparing our reserve estimates, Ryder Scott 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.

Ryder Scott prepares 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. Ryder Scott's final estimated reserve report is reviewed and approved by our engineering staff and management.

The professional qualifications of the internal 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 Chemical Refining Engineering with a minor in Petroleum Engineering, has over 35 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and is a registered Professional Engineer in the State of Colorado.

The SEC's reserve rules expanded the technologies that a registrant may use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

We used a combination of production and pressure performance, wireline wellbore measurements, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserve estimates, including the material additions to the 2012 reserve estimates.

Reserve estimates involve judgments and, therefore, cannot be measured exactly. 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 of discounted future net cash flows ("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 unaudited Supplemental Information - Natural Gas and Crude Oil Information provided with our consolidated financial statements included elsewhere in this report. The following tables provide information regarding our estimated proved reserves:



	As of December 31,
	2012 (5)		2011 (4)(5)		2010 (4)(5)
Proved reserves
Natural gas (MMcf)	604,038		672,145		657,306
Crude oil and condensate (MBbls) (1)	59,310		37,636		23,236
NGLs (MBbls) (1)	32,827		19,588		10,649
Total proved reserves (MMcfe)	1,156,860		1,015,489		860,616
Proved developed reserves (MMcfe) (2)	490,515		471,347		301,141
Estimated future net cash flows (in millions)	$	2,756	$	2,290	$	1,315
PV-10% (in millions) (3)	$	1,709	$	1,350	$	693
Standardized measure (in millions)	$	1,168	$	941	$	488

___________


(1)	Approximately 49% of the increase in crude oil and condensate and 38% of the increase in NGLs from December 31, 2011 to December 31, 2012 is due to the addition of horizontal Niobrara and Codell proved developed and undeveloped reserves in the Wattenberg Field.


(2)	Approximately 73% of the increase in proved developed reserves from December 31, 2010 to December 31, 2011 was due to the reclassification of our estimated Wattenberg refracture reserves from PUDs to proved developed as a result of the greater cost differential between the cost of a refracture versus the cost of drilling a new well.

(3)

PV-10% is a non-U.S. GAAP financial measure. This non-U.S. GAAP measures is not a measure of financial or operating performance under U.S. GAAP and it is not intended to represent the current market value of our estimated reserves. PV-10% should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10% and a reconciliation of our PV-10% value to the standardized measure.


(4)	Includes estimated reserve data related to our Permian assets, which were classified as held for sale as of December 31, 2011. On February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets.

The following table sets forth information regarding estimated proved reserves for our Permian assets:



	As of December 31,
	2011		2010
Proved reserves
Natural gas (MMcf)	6,242		4,979
Crude oil and condensate (MBbls)	7,825		3,331
NGLs (MBbls)	1,971		1,190
Total proved reserves (MMcfe)	65,018		32,105
Proved developed reserves (MMcfe)	15,940		11,416
Estimated future net cash flows (in millions)	$	348	$	129


(5)	Includes estimated reserve data related to our Piceance and NECO assets, which are to be divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets.

The following table sets forth information regarding estimated proved reserves for our Piceance and NECO assets:



	As of December 31,
	2012		2011		2010
Proved reserves
Natural gas (MMcf)	83,656		354,080		454,886
Crude oil and condensate (MBbls)	148		441		548
NGLs (MBbls)	—		—		—
Total proved reserves (MMcfe)	84,544		356,726		458,174
Proved developed reserves (MMcfe)	84,544		141,802		142,949
Estimated future net cash flows (in millions)	$	43	$	32	$	52



	As of December 31, 2012
Operating Region/Area	Natural Gas (MMcf)	NGLs (MBbls)	Crude Oil and Condensate (MBbls)	Natural Gas Equivalent (MMcfe)	Percent
Proved developed
Western
Wattenberg Field	158,192	14,353	20,226	365,666	74	%
Piceance Basin	65,609	—	148	66,497	14	%
Other	18,047	—	—	18,047	4	%
Total Western	241,848	14,353	20,374	450,210	92	%
Eastern
Appalachian Basin	40,077	—	38	40,305	8	%
Total Eastern	40,077	—	38	40,305	8	%
Total proved developed	281,925	14,353	20,412	490,515	100	%
Proved undeveloped
Western
Wattenberg Field	183,618	18,474	38,898	527,850	79	%
Total Western	183,618	18,474	38,898	527,850	79	%
Eastern
Appalachian Basin	138,495	—	—	138,495	21	%
Total Eastern	138,495	—	—	138,495	21	%
Total proved undeveloped	322,113	18,474	38,898	666,345	100	%
Proved reserves
Western
Wattenberg Field	341,810	32,827	59,124	893,516	77	%
Piceance Basin	65,609	—	148	66,497	6	%
Other	18,047	—	—	18,047	2	%
Total Western	425,466	32,827	59,272	978,060	85	%
Eastern
Appalachian Basin	178,572	—	38	178,800	15	%
Total Eastern	178,572	—	38	178,800	15	%
Total proved reserves	604,038	32,827	59,310	1,156,860	100	%

Developed and Undeveloped Acreage

The following table presents our developed and undeveloped lease acreage:



		As of December 31, 2012
		Developed		Undeveloped (1)		Total
Operating Region/Area		Gross	Net	Gross	Net	Gross	Net
Western
Wattenberg Field		92,300	81,700	33,100	23,300	125,400	105,000
Piceance Basin		3,100	3,100	4,900	4,900	8,000	8,000
NECO		23,600	19,600	64,600	54,600	88,200	74,200
Other		—	—	21,800	17,700	21,800	17,700
Total Western		119,000	104,400	124,400	100,500	243,400	204,900
Eastern
Appalachian Basin, other	—	263,900	107,300	32,000	17,950	295,900	125,250
Utica Shale		800	400	48,200	45,300	49,000	45,700
Total Eastern		264,700	107,700	80,200	63,250	344,900	170,950
Total acreage		383,700	212,100	204,600	163,750	588,300	375,850

__________


(1)	With the exception of our Eastern Operating Region properties prospective for the Utica Shale, substantially all of our undeveloped acreage is related to leaseholds that are held by production. Approximately 10% of our undeveloped leaseholds expire during 2013, none of which is material to any one specific area.

Drilling Activity

The following table presents information regarding the number of wells drilled or participated in and the number of wells for which refractures and/or recompletions were performed:



	Drilling Activity
	Year Ended December 31,
	2012		2011		2010
Operating Region	Gross	Net	Gross	Net	Gross	Net
Western (1)	57	39.0	186	139.6	204	164.9
Eastern	6	4.0	9	5.2	9	5.2
Total wells drilled	63	43.0	195	144.8	213	170.1
Refractures and Recompletions (2)	85	79.9	192	177.6	46	33.7

__________


(1)	Includes drilling activity in the Permian Basin. As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets.


(2)	83 of the refractures and recompletions in 2012 occurred in the Wattenberg Field.

The following tables set forth our developmental and exploratory well drilling activity. 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 are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection during the period.



	Net Development Well Drilling Activity
	Year Ended December 31,
	2012				2011			2010
Operating Region/Area	Productive	In-Process		Dry	Productive	In-Process	Dry	Productive	In-Process	Dry
Western
Wattenberg Field	31.3	7.7	(2)	—	86.5	13.1	—	106.9	26.5	—
Piceance Basin	—	—		—	14.0	3.0	—	18.0	7.0	—
Permian Basin (1)	—	—		—	14.5	5.5	2.0	—	5.0	—
Other	—	—		—	—	—	—	0.5	—	—
Total Western	31.3	7.7		—	115.0	21.6	2.0	125.4	38.5	—
Eastern
Appalachian Basin	1.5	—		—	0.9	2.0	—	0.6	1.1	—
Total Eastern	1.5	—		—	0.9	2.0	—	0.6	1.1	—
Total net development wells	32.8	7.7		—	115.9	23.6	2.0	126.0	39.6	—

__________


(1)	As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets.


(2)	On a gross basis, wells in-process as of December 31, 2012 consisted of 10 wells in the Wattenberg Field.



	Net Exploratory Well Drilling Activity
	Year Ended December 31,
	2012			2011			2010
Operating Region/Area	Productive	In-Process	Dry	Productive	In-Process	Dry	Productive	In-Process	Dry
Western
Wattenberg Field	—	—	—	—	—	—	—	1.0	—
Other	—	—	—	—	1.0	—	—	—	—
Total Western	—	—	—	—	1.0	—	—	1.0	—
Eastern
Appalachian Basin	—	1.5	1.0	—	2.3	—	2.8	0.7	—
Total Eastern	—	1.5	1.0	—	2.3	—	2.8	0.7	—
Total net exploratory wells	—	1.5	1.0	—	3.3	—	2.8	1.7	—

Title to Properties

We believe that we hold good and defensible leasehold title to our natural gas and crude oil properties, in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary title examination is typically 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 in the industry. The properties may also be subject to additional burdens, liens or encumbrances customary in 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 our use of the properties.

Substantially all of our natural gas and crude oil properties, excluding properties held by PDCM and our share of the limited partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. Substantially all of our Eastern Operating Region properties, excluding our Ohio properties, have been pledged as security for PDCM's credit facility. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report.

Facilities

We lease 41,710 square feet of office space in 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 18,600 square feet of office space in a second building through October 2014.

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


•	Colorado: Evans, Parachute and Wray


•	Pennsylvania: Indiana and Mahaffey


•	West Virginia: Bridgeport, Buckhannon and Glenville


•	Ohio: Marietta

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 that are beyond our control. These factors include, but are not limited to, 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. In general, state and federal regulations are intended to protect consumers from unfair treatment and oppressive control, reduce environmental and health risks from the development and transportation of natural gas and crude oil, prevent misuse of natural gas and crude oil and protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state and local agencies. In the western part of the U.S., governments own a large percentage of the land and control the right to develop natural gas and crude oil. Government leases may be subject to additional regulations and controls not common to private leases. 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 on the regulation of the U.S. oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental directives 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 where the well being drilled is located. Additionally, other regulated matters include:


•	bond requirements in order to drill or operate wells;


•	well locations;


•	drilling and casing methods;


•	surface use and restoration of well properties;


•	well plugging and abandoning;


•	fluid disposal; and


•	air emissions.

In addition, our drilling activities involve hydraulic fracturing, which may be subject to additional federal and state disclosure and regulatory requirements discussed in "Environmental Matters" below and in Item 1A, Risk Factors.

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. State 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. State or federal leases often include additional regulations and conditions. 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. These laws and regulations, and any others that are passed by the jurisdictions where we have production, can limit the total number of wells drilled or the allowable production from successful wells, which can limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas. 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 Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("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 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 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. 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 restrictive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken restricting drilling or imposing environmental protection requirements resulting in increased costs, our business and prospects may be adversely affected.

We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have adopted requirements that limit the approved disposal methods 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 may subject us to more rigorous and costly operating and disposal requirements.

Hydraulic fracturing is commonly used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations. We routinely apply fracturing in our natural gas and crude oil production programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA"), and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

Certain states in which we operate, including Colorado, Pennsylvania and Ohio, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, transparency and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In December 2011, Colorado adopted a fracturing chemical disclosure rule, wherein all chemicals used in the hydraulic fracturing of a well must be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission ("Frac Focus"). The new rules also require operators seeking new location approvals to provide certain disclosures regarding fracturing to surface owners and adjacent property owners within 500 feet of a new well. In December 2012 and February 2013, Colorado finalized a baseline groundwater sampling rule and a new rule governing setback distances of oil and gas wells located near population centers. See further discussion in Item 1A, Risk Factors.

In December 2011, West Virginia enacted the Natural Gas Horizontal Well Control Act and amendments to existing laws that together establish a comprehensive, detailed system for permitting and regulation of horizontal natural gas wells. The new law applies to most proposed new natural gas wells. The law imposes far more detailed permitting and regulatory requirements than prior law, and requires further study and authorizes potential rulemaking by the West Virginia Department of Environmental Protection ("DEP"). Among the new regulatory requirements are: detailed surface owner compensation requirements; performance standards applicable to disposal of drilling cuttings and associated drilling mud, protection of quantity and quality of surface and groundwater systems; advance designation of water withdrawal locations to the DEP and recordkeeping and reporting for all flowback and produced water; and restrictions on well locations. In early 2012, officials of the Ohio Department

of Natural Resources imposed a moratorium on injection drilling of wastewater from fracturing operations within a five-mile radius of a well that was suspected as contributing to the cause of earthquakes in the area. Regulation was also enacted requiring the disclosure of chemicals used in hydraulic fracturing and any chemicals used when drilling through a drinking water zone.

The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. The U.S. Department of the Interior is conducting a rule making, likely to result in new disclosure requirements and other mandates for hydraulic fracturing on federal lands. These ongoing studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

In Colorado, local governing bodies have begun to issue drilling moratoriums, develop jurisdictional siting, permitting and operating requirements, and conduct air quality studies to identify potential public health impacts. For instance, the City of Fort Collins, Colorado, adopted on February 19, 2013 a ban on drilling and fracturing of new wells within city limits. If new laws or regulations that significantly restrict hydraulic fracturing or well locations are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. If hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays, as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that we are ultimately able to produce from our reserves.

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 have operated prior to the enactment of applicable laws now governing these areas, or 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 ("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 may be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or remediate property contamination (including surface and 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 are subject to the federal Clean Air Act ("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. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. The New Source Performance Standards regarding oil and gas operations ("NSPS 0000") introduced by the EPA in 2011 became effective in 2012, adding administrative and operational costs. Colorado partially adopted the requirements of NSPS 0000 in 2012 and will consider full adoption in 2013.

The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the U.S. The CWA also regulates storm water run-off from natural gas and crude oil facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon 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 additional SPCC measures relating to the possible discharge of crude oil into surface waters. The

Oil Pollution Act of 1990 ("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. 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 enhances our risks related to soil and water contamination.

Our costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2013 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, to our consolidated financial statements included elsewhere 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 and crude oil. 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 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 transportation pipelines, crude oil refineries or natural gas processing facilities. Such an event could result in significantly lower regional prices or our inability to deliver gas.

Competition and Technological Changes

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, evaluate and select suitable properties and 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 will increase in the future.

Recently, certain regions experienced strong demand for drilling services and supplies, which resulted in increasing costs. Our Wattenberg Field and Eastern Operating Region experienced intense competition for drilling and pumping services. 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. Should economic conditions deteriorate and financing become more expensive and difficult to obtain, we may not have adequate capital to execute our business plan and we may be forced to curtail our drilling and acquisition activities.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations and cash flows could be materially adversely affected.

Employees

As of December 31, 2012, we had 421 employees. Our employees are not covered by a collective bargaining agreement. We consider relations with our employees to be 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.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.pdce.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 PDC Energy Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (800) 624-3821.

We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, 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 website, the information available on our website is not part of this report and is not hereby incorporated by reference.

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.

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

Our revenue, profitability and cash flows depend in large part upon the prices and demand for natural gas, NGLs and crude oil. The markets for these commodities can be volatile, and significant drops in prices can negatively affect our financial results and impede our growth. For example, in much of 2012, natural gas prices were too low to economically justify drilling operations in several areas, and the outlook for natural gas prices remains weak due largely to increased supply and large inventories in storage. Similarly, NGL prices have decreased in some recent periods due to increased development activities in a variety of basins across the U.S. Changes in commodity prices have a significant effect on our cash flows and on the value and quantity of our reserves, which can in turn reduce the borrowing base under our revolving credit facility. Prices for natural gas, NGLs and crude oil may fluctuate in response to relatively minor changes in supply and demand, 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 substantial reduction in the growth rate of China could affect global oil prices significantly, and continued weakness in the overall economic environment could adversely affect all commodity prices. In addition to factors affecting the price of oil, NGLs and natural gas generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. Pricing can be influenced by, among other things, local or regional supply and demand factors (such as refinery or pipeline capacity issues, trade restrictions and governmental regulations) and the terms of our sales contracts.

Lower commodity prices may not only reduce our revenues, but also may reduce the amount of natural gas, NGLs and crude oil that we can produce economically. As a result, we may have to make substantial downward adjustments to our estimated proved reserves if prices decline or remain at depressed levels for extended periods. 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 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. For example, in 2011, we recorded an impairment charge related to our NECO proved natural gas and crude oil properties of $22.5 million and in 2012 we recorded an impairment charge of $161.2 million related to our Piceance Basin proved oil and natural gas properties. We may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations.

The marketability of our production is dependent upon limited transportation and processing facilities over which we may have no control. Market conditions or operational impediments, including high line pressures, particularly in the Wattenberg Field, and other impediments affecting gathering and transportation systems, could hinder our access to natural gas, crude oil and NGL markets or delay production and thereby adversely affect our profitability.

Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate gathering, processing and transportation facilities are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. For example, due to increased drilling activities by third parties and unusually hot temperatures in Colorado in the second half of 2012, the principal third-party provider we use in the Wattenberg area for these facilities and services experienced high line pressure, and the resulting capacity constraints impacted the productivity of some of our older wells and limited the incremental production impact of our newer horizontal wells. As a result, we have seen an impact on our production and a related decrease in revenue from the impacted wells. Thus, our profitability has been adversely affected, and will continue to be affected until available capacity increases or alternative arrangements are available. Additional pipelines and facilities are being planned for the area but are not expected to be completed until the latter part of 2013. Capacity constraints affecting natural gas production also impact our ability to produce the associated NGLs. We may face similar risks in other areas, including our Utica operating area, as gathering/processing infrastructure is currently in the development phase. We are also dependent on third party pipeline infrastructure to deliver our natural gas production to market in the Marcellus and Piceance Basin areas.

Federal, state and local legislative and regulatory initiatives and litigation relating to hydraulic fracturing could result in increased costs and additional drilling and operating restrictions or delays in the production of natural gas, NGLs 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 and litigation could adversely affect our financial condition, results of operations and cash flows.

Most of our drilling uses hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of unconventional wells in shale, coalbed and tight sand formations. 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 Safe Drinking Water Act (“SDWA”), and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), or other laws. Sponsors of these bills, which have been subject to various proceedings in the legislative process, including in 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 Environmental Protection Agency (the “EPA”) has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, and conducted public meetings around the country on this issue which have been well publicized and well attended. In March 2011, 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 EPA issued an initial report about the study in December 2012. The initial report described the focus of the continuing study but did not include any data concerning EPA's efforts to date, nor did it draw any conclusions about the safety of hydraulic fracturing. Final results, including data and conclusions, are expected in 2014.

The EPA has also begun a Toxic Substances Control Act rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. EPA also has finalized major new Clean Air Act (“CAA”) standards (New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPs) applicable to hydraulically fractured natural gas wells. The standards will require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions from well completions as well as new controls applicable to a wide variety of storage tanks. While most key provisions in the new CAA standards are not effective until 2015, the rules associated with such standards are substantial and may increase future costs of our operations and will require us to make modifications to our operations and install new equipment. EPA has also issued and is in the process of finalizing permitting guidance for hydraulically fractured wells where diesel is used. It remains to be seen how broadly applicable the diesel guidance will be, but it has the potential to create duplicative requirements, further slow down the permitting process in certain areas, and increase the costs of operations. Certain other federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. The U.S. Department of the Interior, through the Bureau of Land Management, is currently conducting a rulemaking that will require, among other things, disclosure of chemicals and more stringent well integrity measures associated with hydraulic fracturing operations on public land.

In addition, certain state governments, including the states of Colorado, Pennsylvania, Ohio, and West Virginia, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting, disclosure, wastewater disposal, baseline sampling, well construction and well location requirements on hydraulic fracturing operations or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. Some municipalities and local governments, including most recently the city of Fort Collins in Colorado, have adopted or are considering similar actions. In addition, lawsuits have been filed against unrelated third parties in Pennsylvania, New York, Arkansas and several other states 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, crude oil and NGL production activities using hydraulic fracturing techniques. Additional legislation, regulation, or litigation could also lead to operational delays or lead us to incur increased operating costs in the production of natural gas, NGLs and crude oil, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing or other drilling activities. If these legislative, regulatory, and litigation initiatives cause a material decrease in the drilling of new wells and in related servicing activities, our profitability could be materially impacted.

Environmental and overall public scrutiny focused on the oil and gas industry is increasing. 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 our 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 natural resource or other damages. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance 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. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years-particularly with respect to hydraulic fracturing-and environmental organizations have opposed, with some success, certain drilling projects.

In addition, our activities are subject to regulations governing conservation practices, protection of wildlife and habitat 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, NGLs and crude oil that we can produce and market. A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from state and local authorities in a timely manner. Delays in obtaining regulatory approvals or 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 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. At the state level, for instance, the Colorado Oil and Gas Conservation Commission (“COGCC”) issued a new rule governing mandatory minimum spacing, or setbacks, between oil and gas wells and occupied buildings and other areas. Similarly, it is expected that the COGCC may undertake a rulemaking focused on wellbore integrity in 2013 that would increase requirements in this area. In addition to increasing costs of operation, these rules could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues. The COGCC has also recently concluded a rulemaking that will require baseline sampling of certain

ground and surface water in most areas of Colorado. These new sampling requirements could increase the costs of developing wells in certain locations.

Some local governmental bodies, for instance Longmont, Colorado, have adopted or are considering regulations regarding, among others things, land use, requiring the posting of bonds to secure restoration obligations and limiting hydraulic fracturing and other drilling activities, and these regulations may limit, delay or prohibit exploration and development activities or make those activities more expensive. Additionally, state and local governments are undertaking air quality studies to assess potential public health impacts from oil and gas operations. These studies may result in the imposition of additional regulatory requirements on oil and gas operations.

The BP crude oil spill in the Gulf of Mexico and generally heightened industry scrutiny has resulted and may result in new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, and conducted public meetings around the country on this issue which have been well publicized and well attended. This renewed focus could lead to additional federal, state and local laws and regulations affecting our drilling, fracturing and other operations.

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 flows, in addition to undermining the demand for the natural gas, NGLs and crude oil we produce.

Our ability to produce natural gas and crude oil could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules.

Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). In addition, Colorado and other western states have recently experienced a drought. As a result, future availability of water from certain sources used in the past may be limited. Moreover, the imposition of new environmental initiatives and conditions could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. The federal Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas waste, into navigable waters or other regulated state waters. Permits or other approvals must be obtained to discharge pollutants to regulated waters and to conduct construction activities in such waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters has, and will continue to, complicate and increase the cost of obtaining such permits or other approvals. The CWA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations, and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA, prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into coastal waters. While generally exempt under federal programs, many state agencies have also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. In October 2011, the EPA announced its intention to develop federal pretreatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the pretreatment rules will require coalbed methane and shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected in 2013 for coalbed methane production and in 2014 for shale gas production. Some states, including Pennsylvania, have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There has been recent nationwide concern, particularly in Ohio, over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. It is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others. Finally, the EPA study noted above has focused and will continue to focus on various stages of water use in hydraulic fracturing operations. It is possible that, following the conclusion of EPA's study, the agency will move to more strictly regulate the use of water in hydraulic fracturing operations. While we cannot predict the impact that these changes may have on our business at this time, they may be material to our business, financial condition, and operations. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells or the disposal or recycling of water will increase our operating costs and may cause delays, interruptions or termination of our operations, the extent of which cannot be predicted. In addition, our inability to meet our water supply needs to conduct our completion operations may impact our business, and any such future laws and regulations could negatively affect our financial condition and results of operations.

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

Acquisitions of producing properties and undeveloped properties have been an important part of our historical and recent 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 commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform engineering, environmental, 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. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor.

When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. 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. Therefore, we could incur significant unknown liabilities, including environmental liabilities, or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire.

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 may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition.

Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges.

A substantial part of our natural gas, NGLs and crude oil production is located in the Wattenberg Field, making it vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations.

Our operations are focused primarily on the Wattenberg Field in our Western Operating 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, NGLs and crude oil produced from the wells in the area, 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 Wattenberg Field has contributed to bottlenecks in processing and transportation that have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our assets within a small number of producing formations, in particular the Niobrara, Codell and Marcellus formations, exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition.

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, crude oil and NGL reserve engineering requires subjective estimates of underground accumulations of natural hydrocarbons and assumptions concerning commodity 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, NGLs and crude oil reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding commodity prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual results could greatly affect:


•	the economically recoverable quantities of natural gas, NGLs 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 histories, which renders these reserve estimates less reliable than estimates based on longer production histories. Horizontal drilling in the Wattenberg field is a relatively recent development, whereas vertical drilling has been used by producers in this field for over 40 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small, and future reserve estimates will be affected by additional production data as it becomes available. Further, reserve estimates are based on the volumes of natural gas, NGLs and crude oil that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of natural gas, NGLs and crude oil recovered would be different than the reserve estimates since they would not be produced under the same economic conditions as used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves and are less likely to be recovered.

At December 31, 2012, approximately 57.6% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $1.6 billion during the five years ending in 2017. You should be aware that the estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to downgrade any PUDs that are not developed within this five-year time frame to probable or possible.

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 prior 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, NGLs 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, crude oil and NGL 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 properties or the industry in general.

Unless 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, crude oil and NGL reservoirs are generally 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. The rate can change due to other circumstances as well. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire 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. Our failure to do so would adversely affect our future operations, financial condition and results of operations.

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

We have previously disclosed our intention to pursue, beginning in the fall of 2010 and extending through 2013, the acquisition of the limited partnership units held by non-affiliated investor partners in the drilling partnerships that we have sponsored. We have not budgeted for the acquisition of the largest remaining partnership in 2013. We also may be unable to make additional acquisitions of such affiliated drilling partnerships since consummation of any such acquisitions may be subject to the same procedural processes that were utilized in connection with our previously completed acquisitions of public drilling partnerships. Such procedural hurdles previously included, and may in the future include, among others:


•	negotiation and execution of a merger agreement with a special committee, comprised entirely of non-employee directors, of our board of directors;


•	clearance from the SEC upon completion by each of the partnerships of their SEC proxy disclosure review process before the partnerships can request approval of the merger transactions from their non-affiliated investors; and


•	approval by the holders of a majority of the limited partnership units held by the non-affiliated investors of each respective partnership.

In addition, certain former non-affiliated investor partners have initiated litigation concerning our acquisition of twelve limited partnerships in 2010 and 2011. Litigation challenges to further acquisitions are also possible. In addition, we will have incurred, and will remain liable for, transaction costs, including legal, accounting, financial advisory and other costs relating to any prospective acquisitions, including the costs of the financial and legal consultants to the special committee of our board of directors, whether or not the acquisitions are consummated. We currently do not have any drilling partnership acquisitions pending or planned in 2013. The occurrence of any of the risks associated with these potential transactions individually or in combination could have an adverse effect on our business, financial condition or results of operations.

When drilling prospects, the wells we drill may not yield natural gas, NGLs 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 hydrocarbon-bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether natural gas, NGLs or crude oil will be present at all or 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, NGLs 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, NGLs 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 the value of our properties will likely be reduced. These risks are greater in developing areas such as the Utica Shale, where we are currently investing substantial capital. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period.

Drilling for and producing natural gas, NGLs and crude oil are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. Our drilling risk exposure may be increased as we have allocated most of our 2013 capital budget to drilling horizontal wells.

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;


•	loss of well control;


•	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. For example, 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 for 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 maintain insurance against various losses and liabilities arising from operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or the governmental response to an event could have a material adverse effect on our business activities, financial condition and results of operations. 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 elsewhere in this report.

Our business strategy focuses on production in our liquid-rich and high impact shale plays. In this regard, we plan to allocate our capital to an active horizontal drilling program. Historically, most of the wells we drilled were vertical wells. In 2012 and 2013, however, we have devoted the majority of our capital budget to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells, including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore, and thus the risk of failure is greater than the risk involved in drilling vertical wells. Additionally, drilling horizontal wells is far costlier than drilling vertical wells. Consequently, because we are drilling far fewer total wells during 2013 as compared to many prior years, the risk of drilling a non-economic well will be relatively higher than if we were to drill a similar number of wells as we did in those prior years. Furthermore, because of the relatively higher cost in drilling horizontal wells, a completed well to be successful economically will need to have production that will cover the higher drilling costs. While we believe that we will be better served by our drilling horizontal wells, the risk component involved in such drilling will be increased, with the result that we might find it more difficult to achieve economic success in our horizontal drilling program.

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 conduct exploratory drilling 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 in which the wells 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 could 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 add new reserves that exceed our production over time 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 in some basins. The acquisition market for 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 2011 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 the carrying value of our crude oil properties in response to any future decrease in commodity prices and/or reduction in the profitability of our operations.

Depressed natural gas prices could result in significant impairment charges and significant downward revisions of proved natural gas reserves.

The domestic natural gas market remains weak. Low natural gas prices could result in significant impairment charges in the future. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management's estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward natural gas prices alone could result in a significant impairment for our properties that are sensitive to declines in natural gas prices. In December 2012, we recognized an impairment charge of $161.2 million associated with our Piceance Basin proved oil and natural gas properties and similar charges could occur in the future. In addition, low natural gas prices could result in significant downward revisions to our proved natural gas reserves.

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 production and 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, crude oil and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and from capital markets transactions and the sale of properties. 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, NGLs and crude oil we are able to produce from existing wells;


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


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


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

If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources would increase. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. 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. We intend to fund a portion of our 2013 capital expenditures with proceeds from our sale of Piceance Basin and certain other properties to Caerus. There can be no assurance that this transaction will close as planned. In addition, purchase price adjustments may reduce our proceeds from the transaction.

We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt.

We have a substantial amount of indebtedness. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. As of December 31, 2012, we had $676.6 million in outstanding indebtedness and approximately $382.3 million available to be borrowed under our revolving credit facility, subject to limitation under our financial covenants.

Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flows from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend upon our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flows from operations, or that future borrowings will be available to us under our revolving credit facility or otherwise, in an amount sufficient to fund our liquidity needs.

A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, refinancing all or a portion of our existing debt or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of future debt agreements may, and our existing debt agreements do, restrict us from implementing some of these alternatives. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due.

Our substantial indebtedness could adversely impact our business, results of operations and financial condition.

In addition to making it more difficult for us to satisfy our debt and other obligations, our substantial indebtedness could limit our ability to respond to changes in the markets in which we operate and otherwise limit our activities. For example, our indebtedness, and the terms of agreements governing that indebtedness, could:


•	require us to dedicate a substantial portion of our cash flows from operations to service our existing debt obligations, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;


•	increase our vulnerability to economic downturns and impair our ability to withstand sustained declines in commodity prices;


•	subject us to covenants that limit our ability to fund future working capital, capital expenditures, exploration costs and other general corporate requirements;


•	prevent us from borrowing additional funds for operational or strategic purposes (including to fund future acquisitions), disposing of assets or paying cash dividends;


•	limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;


•	require us to devote a substantial portion of our cash flows from operations to payments on our indebtedness, thereby reducing the availability of our cash flows to fund exploration efforts, working capital, capital expenditures and other general corporate purposes; and


•	place us at a competitive disadvantage relative to our competitors that have less debt outstanding.

Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions.

The indenture governing our senior notes and our revolving credit facility contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and certain of our subsidiaries' ability to:


•	incur additional debt;


•	pay dividends on, redeem or repurchase stock;


•	create liens;


•	make specified types of investments;


•	apply net proceeds from certain asset sales;


•	engage in transactions with our affiliates;


•	engage in sale and leaseback transactions;


•	merge or consolidate;


•	restrict dividends or other payments from restricted subsidiaries;


•	sell equity interests of restricted subsidiaries; and


•	sell, assign, transfer, lease, convey or dispose of assets.

Our revolving credit facility will mature on November 5, 2015, and is secured by all of our oil and gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility.

Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices.

We depend in large part on our revolving credit facility for future capital needs. The terms of the credit 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 agreements could result in a default under those agreements, 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 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, crude oil and NGL 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 revolving credit facility could adversely affect our operations and our financial results.

If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there would be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on our indebtedness and satisfy our other obligations.

Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to seek to obtain waivers from the required lenders under our revolving credit facility to avoid being in default. If we breach our covenants under our revolving credit facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease.

Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above.

We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we and our subsidiaries now face.

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 wildlife affect operations in our Western Operating Region. In certain areas, including parts of the Piceance Basin in Colorado, drilling and other 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 the active 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. Similarly, hot weather during parts of 2012 adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows.

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 89% 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 the underlying properties. 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. 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.

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 the production from our own wells, our partnerships and for natural gas purchases and sales by our marketing subsidiary to achieve a more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, 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 counterparty 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 we would otherwise receive from increases in the prices for the relevant commodity. 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 it would be if our derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income.

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

Substantially all of our accounts receivable result from our natural gas, NGLs 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 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. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage.

Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.

As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows.

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 also do not carry contingent business interruption insurance related to the purchasers of our production. In addition, pollution and environmental risks 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. 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, our competitors 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, NGLs 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 properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. 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, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local

and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect the success of our operations and our profitability.

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 2012, U.S. President Barack Obama and his administration released its budget proposals for the fiscal year 2013, which included numerous proposed tax changes. The proposed budget, if enacted, would eliminate certain key U.S. federal income tax preferences currently available with respect to natural gas and crude oil exploration and production. Similar changes have been in previous budget proposals from the Obama administration but were not adopted into law. The changes in the current budget proposal related to oil and gas drilling and production 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 result in higher federal income taxes, which could negatively affect our financial condition and results of operations.

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 commodity hedging swaps, and could have a number of adverse effects on us, including the following:

•

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


•	If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.


•	Our derivatives counterparties will be subject to significant new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us.


•	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, NGLs 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 provide the basis for the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (the “CAA”). In June 2010, the EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the CAA's 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,” ("BACT") standards. In its permitting guidance for greenhouse gases, issued on November 10, 2010, the EPA recommended options for BACT, which include improved energy efficiency, among others. EPA has recently issued a final rule retaining the current “tailored” permitting thresholds, opting not to extend greenhouse gas permitting requirements to smaller stationary sources at this time. The EPA, however, intends to revisit these thresholds again by 2016. In addition, on June 26, 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion and order in Coalition for Responsible Regulation v. Environmental Protection Agency, No. 09-1322, upholding EPA's greenhouse gas-related rules, including the “Tailoring Rule,” against challenges from various state and industry group petitioners. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require us to incur costs to reduce and monitor 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 in 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. We are required to report our greenhouse gas emissions on an annual basis, 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. The ACESA was not passed by the U.S. Senate. However, many states and regions have 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. Recently, increased focus has been directed to methane emissions, including a lawsuit by several Northeastern states that would require the EPA to more stringently regulate methane emissions from the oil and gas sector. The passage of legislation, or other initiatives, that limit 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 damage 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.

The cost of defending any suits brought against us with respect to our royalty payment practices, and any judgments resulting from such suits, could have an adverse effect on our results of operations and 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. We intend to defend ourselves vigorously in these cases. The costs of defending these suits can be significant, even when we ultimately succeed in having them dismissed. 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. A judgment in favor of a plaintiff in a suit of this type could have a material adverse effect on our financial condition and profitability.

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 factors, including the availability of capital, regulatory approvals, commodity prices, competition, costs, availability of drilling rigs, drilling results and the ability of our geologists to successfully identify potentially successful new areas to develop. All of these factors are subject to numerous uncertainties. 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.

PDCM is dependent upon our equity partner 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 our equity partner Lime Rock Partners, LP, 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 Lime Rock 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, Lime Rock 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 its ownership interests to a third party. Lime Rock 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 years following the closing of the joint venture, Lime Rock 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 Lime Rock's ownership interests, Lime Rock 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 Lime Rock's interest under the rights of first offer and refusal, Lime Rock might sell its interests in the joint venture to a third party with whom we might have a difficult time dealing and in managing the joint venture or 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.

Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.

Our articles of incorporation, bylaws, stockholders rights plan and Nevada law contain provisions that may have an anti-takeover effect and may delay, defer or prevent a tender offer or takeover attempt, which may adversely affect the market price of our common stock.

Our articles of incorporation authorize our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. We previously adopted a stockholders rights plan that will dilute the stock ownership of certain acquirers of our common stock upon the occurrence of certain events. In addition, some provisions of our articles of incorporation, bylaws and Nevada law could make it more difficult for a third party to acquire control of us, including:


•	the organization of our board of directors as a classified board, which allows no more than one-third of our directors to be elected each year;


•	limitations on the ability of our shareholders to call special meetings; and


•	certain antitakeover provisions of the Nevada private corporations statute.

Because we have no plans to pay dividends on our common stock, stockholders must look solely to stock appreciation for a return on their investment in us.

We have never declared or paid cash dividends on our common stock. We currently intend to retain all future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our revolving credit facility and the indenture governing our senior notes limit our ability to pay cash dividends on our common stock. Any future dividends may also be restricted by any other debt agreements which we may enter into from time to time.

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 elsewhere in this report.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. The following table sets forth 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, 2011	$	49.60	$	39.93
April 1 - June 30, 2011	48.51		28.67
July 1 - September 30, 2011	39.50		19.35
October 1 - December 31, 2011	37.77		15.08
January 1 - March 31, 2012	40.26		28.61
April 1 - June 30, 2012	37.63		19.33
July 1 - September 30, 2012	34.25		23.27
October 1 - December 31, 2012	36.55		25.76

As of February 8, 2013, we had approximately 726 shareholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility and the indenture governing our 2022 Senior Notes and we presently intend to continue a policy of using retained earnings for expansion of our business. See Note 8, Long-term Debt, to our consolidated financial statements included elsewhere in this report.

The following table presents information about our purchases of our common stock during the three months ended December 31, 2012:



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, 2012	709	$	31.93	—	—
November 1 - 30, 2012	9,786	31.53		—	—
December 1 - 31, 2012	254	33.25		—	—
Total fourth quarter purchases	10,749	31.59

__________


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

SHAREHOLDER PERFORMANCE GRAPH

The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2012, 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 254 crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2007 and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance.

ITEM 6. SELECTED FINANCIAL DATA



	Year Ended December 31,
	2012			2011			2010			2009			2008
	(in millions, except per share data and as noted)
Statement of Operations:
Natural gas, NGLs and crude oil sales	$	270.3		$	276.6		$	205.0		$	171.2		$	304.9
Commodity price risk management gain (loss), net	32.3			46.1			59.9			(10.1		)	127.8
Total revenues	356.1			396.0			343.0			230.9			572.5
Income (loss) from continuing operations	(144.8		)	3.1			6.0			(80.1		)	105.8

Earnings per share from continuing operations
Basic	$	(5.23	)	$	0.13		$	0.33		$	(4.76	)	$	7.19
Diluted	(5.23		)	0.13			0.32			(4.76		)	7.13

Statement of Cash Flows:
Net cash from:
Operating activities	$	174.7		$	166.8		$	151.8		$	143.9		$	139.1
Investing activities	(451.9		)	(456.4		)	(300.9		)	(142.3		)	(323.0		)
Financing activities	271.4			243.4			171.5			(20.6		)	150.1
Capital expenditures	347.7			334.5			162.7			143.0			323.2
Acquisitions of natural gas and crude oil properties	312.2			145.9			158.1			—			—

Balance Sheet:
Total assets	$	1,826.8		$	1,698.0		$	1,389.0		$	1,250.3		$	1,402.7
Working capital (deficit)	(31.4		)	(22.0		)	16.2			32.9			31.3
Long-term debt	676.6			532.2			295.7			280.7			394.9
Total equity	703.2			664.1			642.2			538.6			512.3

Pricing and Lifting Costs Relating to Continuing Operations (per Mcfe):
Average sales price (excluding gains/losses on derivatives)	$	5.45		$	6.15		$	5.63		$	4.19		$	8.37
Average sales price (including realized gains/losses on derivatives)	6.44			6.53			6.89			6.77			8.62
Average lifting cost (1)	0.85			0.92			1.05			0.78			1.04

Production (Bcfe):
Production from continuing operations	49.6			45.0			37.0			41.6			36.9
Production from discontinued operations	0.4			2.5			1.6			1.7			1.8
Total production	50.0			47.5			38.6			43.3			38.7

Total proved reserves (Bcfe) (2)	1,156.9			1,015.5			860.6			717.3			753.1

______________


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

(2)

Includes total proved reserves related to our Permian Basin assets of 65.0 Bcfe and 32.1 Bcfe as of December 31, 2011 and 2010, respectively. As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets.

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 elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report.

EXECUTIVE SUMMARY

2012 Financial Overview

In 2012, our natural gas, NGLs and crude oil production from continuing operations averaged 135.6 MMcfe per day, an increase of approximately 10% compared to the prior year. The increase in production is primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field and the Merit Acquisition. Crude oil production from continuing operations increased 18.5% in 2012, while NGL production from continuing operations increased 17.0%. As a result, our liquids percentage of total production from continuing operations was 34.7% in 2012 compared 32.4% in 2011. Natural gas production increased 6.5% in 2012 compared to 2011. As discussed under "Operational Overview-Production" below, production growth in 2012 was adversely affected by high line pressures experienced by our principal third-party provider of natural gas gathering, processing and transportation facilities in the Wattenberg Field. The high line pressure, primarily experienced during the second and third quarters, was the result of two primary factors: a series of operational issues experienced by the third-party midstream service provider facilities and abnormally warm weather. While natural gas production increased when compared to prior year, significant declines in the average price of natural gas during 2012 resulted in a decrease in natural gas sales, excluding hedges, of 28.9% year-over-year. The price of natural gas, however, rebounded significantly during the fourth quarter of 2012. During 2012, we recorded an impairment charge of $161.2 million related to our Piceance Basin proved oil and natural gas properties. While the significant decrease in natural gas prices from prior years has impacted our results of operations, we believe our derivative program was effective in providing a degree of price stability. Realized gains from derivative transactions increased considerably to $49.4 million in 2012, compared to $17.2 million in 2011, an addition of approximately $0.99 per Mcfe sold during 2012.

Available liquidity as of December 31, 2012 was $398.6 million, including $14.1 million through our joint venture PDCM, compared to $196.4 million, including $16.6 million related to PDCM, as of December 31, 2011. Available liquidity is comprised of cash, cash equivalents and funds available under our revolving credit facility. In May 2012, we completed a public offering of 6.5 million shares of our common stock for net proceeds of approximately $164.5 million, after deducting underwriting discounts and offering expenses. These funds were used to complete the Merit Acquisition noted below. In October 2012, we issued $500 million aggregate principal amount of our 2022 Senior Notes in a private placement. The net proceeds from the issuance of the notes of approximately $489 million were used to fund the redemption of our 2018 Senior Notes for a total redemption price of approximately $222 million, repay a portion of the amount outstanding under our revolving credit facility and for general corporate purposes. The early redemption of the 2018 Senior Notes resulted in a pre-tax loss on debt extinguishment of approximately $23.3 million. On October 31, 2012, we completed the semi-annual redetermination of our revolving credit facility's borrowing base. Our available borrowing base was reduced from $525 million to $450 million as a result of issuance of our 2022 Senior Notes.

Operational Overview

Acquisitions. We continued to make strides in 2012 toward our strategic goal of growing production while increasing our mix of crude oil and natural gas liquids. In June, we completed the Merit Acquisition for cash consideration of approximately $304.6 million, after certain post-closing adjustments. The acquired assets comprise approximately 29,800 net acres, after post-closing adjustments, located almost entirely in the core Wattenberg Field and with significant overlay with our existing acreage position. Ryder Scott prepared a reserve report with respect to the Merit Acquisition properties and estimated net proved reserves of 29.2 MMBoe (175 Bcfe) based on our development plan, using year-end 2011 SEC pricing and an effective date of April 1, 2012. Following the closing of the Merit Acquisition, our total position in the core Wattenberg Field was approximately 98,600 net acres.

Drilling Activities. During 2012, we continued to focus our operations primarily in the oil- and liquid-rich Wattenberg Field in Colorado and the emerging Utica Shale play in Ohio. We currently have two drilling rigs operating in the Wattenberg Field. We drilled 37 horizontal wells and one vertical well in the Wattenberg Field in 2012, of which 30 were completed and turned-in-line as of December 31, 2012, and we participated in 19 non-operated drilling projects. We also executed 160 refracture and/or recompletion projects on 83 wells in the Wattenberg Field. The shift in the Wattenberg Field from drilling both vertical and horizontal wells to our current program of drilling horizontal wells has resulted in significantly fewer wells being drilled at a considerably higher cost per well and higher production and reserves per well. The remaining activity in our Western Operating Region in 2012 was the first quarter completion of our final three Piceance wells drilled in 2011.

In our Eastern Operating Region, we drilled and completed two horizontal Utica wells during the year. At December 31, 2012, these wells are currently shut-in awaiting pipeline connections. We also drilled and completed one vertical Utica stratigraphic test well and completed one vertical Utica stratigraphic test well drilled in late 2011. In 2012, the costs related to the two vertical stratigraphic test wells were expensed at a cost of $12.2 million. We currently plan to continue to de-risk and develop our approximate 45,000 net acres without materially adding to our leasehold position. We estimate our total gross horizontal Utica Shale drilling inventory to be approximately 200 locations. In addition, PDCM drilled three horizontal Marcellus wells in 2012, all of which were completed and turned-in-line during the year.

Natural Gas and Crude Oil Properties Divestitures. In October 2011, we announced our intent to divest our Permian Basin assets to focus our efforts on our horizontal drilling programs. During the fourth quarter of 2011, we sold certain non-core Permian assets to unrelated

third parties for a total of $13.2 million. On December 20, 2011, we executed a purchase and sale agreement with another unrelated third-party for the sale of our core Permian assets for a total price of $173.9 million, subject to customary post-closing adjustments. On February 28, 2012, the divestiture of the core Permian assets closed. Upon final post-closing adjustments on June 29, 2012, total proceeds received for the core Permian assets was $189.2 million, resulting in a pre-tax gain on sale of $19.9 million. The proceeds from these sales were used to pay down amounts outstanding under our revolving credit facility and to provide partial funding for our 2012 capital budget. The results of operations related to our Permian Basin assets are reported as discontinued operations for all applicable periods presented in the accompanying statements of operations included elsewhere in this report.

2013 Planned Divestiture. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including derivatives, for aggregate cash consideration of approximately $200 million. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence, and by certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus. We intend to use the proceeds from the sale to repay a portion of amounts outstanding under our revolving credit facility and partially fund our 2013 capital program. The assets being sold do not include any of our core Wattenberg Field acreage. As of December 31, 2012, total estimated proved reserves related to these assets were 83,656 MMcf of natural gas and 148 MBbls of crude oil, for an aggregate of 84,544 Mmcfe of natural gas equivalent. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets. There can be no assurance that this transaction will close as planned. In addition, purchase price adjustments may reduce our proceeds from the transaction.

Production. Production from continuing operations increased significantly in 2012 as compared to 2011. In particular, primarily as a result of our Wattenberg Field drilling activities, oil production increased 18.5% and NGL production increased 17%. This production growth was achieved despite high line pressures experienced by our principal third-party provider of natural gas gathering, processing and transportation facilities in the Wattenberg Field. The high line pressure was the result of a series of operational issues experienced by third-party midstream service provider, primarily during the second and third quarter of 2012. The operational issues included downtime on third-party NGL transportation and fractionation facilities and abnormally warm weather, which limited the gathering system compression capacity. We are working closely with this primary midstream provider who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity in the Wattenberg Field. However, we do not expect the impact of this increased capacity to substantially benefit us until late 2013.

Our NGL pricing has also decreased significantly relative to the same period in 2011. Our NGLs are priced at Conway, Kansas, where ethane and propane are valued at a significant discount to Mt. Belvieu gulf coast NGL pricing. The planned 2013 infrastructure projects include a new NGL pipeline that will provide direct access for our NGLs to Mt. Belvieu where we anticipate improved pricing.

Non-U.S. GAAP Financial Measures

We use "adjusted cash flows from operations," "adjusted net income (loss) attributable to shareholders," "adjusted EBITDA" and "PV-10%," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes 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, and should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP. The non-U.S. 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-U.S. 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-U.S. GAAP Financial Measures for a detailed description of these measures, as well as a reconciliation of each to the most comparable U.S. GAAP measure.

Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results from continuing operations:



	Year Ended December 31,
								Change
	2012		2011		2010			2012-2011		2011-2010
	(dollars in millions, except per unit data)
Production (1)
Natural gas (MMcf)	32,409.8		30,429.7		26,239.1			6.5	%	16.0	%
NGLs (MBbls)	841.3		719.2		569.6			17.0	%	26.3	%
Crude oil (MBbls)	2,025.9		1,709.9		1,231.4			18.5	%	38.9	%
Natural gas equivalent (MMcfe) (2)	49,612.4		45,004.8		37,044.9			10.2	%	21.5	%
Average MMcfe per day	135.6		123.3		101.5			10.0	%	21.5	%
Natural Gas, NGLs and Crude Oil Sales
Natural gas	$	70.8	$	99.6	$	94.6		(28.9	)%	5.3	%
NGLs	23.0		27.2		22.6			(15.4	)%	20.4	%
Crude oil	176.5		149.8		91.1			17.8	%	64.4	%
Provision for underpayment of natural gas sales	—		—		(3.3		)	—	%	(100.0	)%
Total natural gas, NGLs and crude oil sales	$	270.3	$	276.6