petro.dev-10K-FY11


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, 2011

or

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

For the transition period from __________ to _________

Commission File Number 000-07246
PETROLEUM DEVELOPMENT CORPORATION
(Exact name of registrant as specified in its charter)
(Doing Business as PDC Energy)
Nevada
95-2636730
(State of Incorporation)
(I.R.S. Employer Identification No.)
1775 Sherman Street, Suite 3000
Denver, Colorado 80203
(Address of principal executive offices) (Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, par value $0.01 per share
 
NASDAQ Global Select Market

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 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  £
Accelerated filer  x
Non-accelerated filer  £
(Do not check if a smaller reporting company)
Smaller reporting company  o

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

The aggregate market value of our common stock held by non-affiliates on June 30, 2011, was $699,417,474 (based on the then closing price of $29.91).

As of February 17, 2012, there were 23,634,456 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 2012 Annual Meeting of Stockholders.





PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
2011 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

 
PART I
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART IV
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 





PART I

REFERENCES TO THE REGISTRANT

In July 2010, Petroleum Development Corporation, established in 1969, began conducting business as PDC Energy. The Company's common stock continues to trade on the NASDAQ Global Select Market under the ticker symbol PETD. The Company's website, www.petd.com, reflects the PDC Energy name and brand identity. At the Company's annual stockholders' meeting to be held in June 2012, we plan to request shareholders to approve and amend the Company's articles of incorporation to formally change the corporate name to PDC Energy, Inc. Information contained on or linked to our website 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," "PDC Energy," "the Company," "we," "us," "our," "ours" or "ourselves" refer to the registrant, Petroleum Development Corporation, 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 ("Marcellus JV"). Unless the context otherwise requires, references in this report to "Appalachian Basin" includes PDC's proportionate share of our affiliated partnerships' and the Marcellus JV'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 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.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the United States Securities and Exchange Commission ("SEC"). Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.petd.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact Petroleum Development Corporation, dba PDC Energy, Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call toll free (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, bylaws, committee charters, code of business conduct and ethics, shareholder communication policy, director nomination procedures and our whistle-blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not hereby incorporated by reference.

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 include: estimated natural gas, natural gas liquids ("NGLs") and crude oil production and reserves; expected operational, midstream and marketing synergies from PDCM's Seneca-Upshur acquisition; anticipated capital expenditures, including our ability to fund our 2012 capital budget; increased focus on the Wattenberg Field and liquid-rich areas; our horizontal Niobrara drilling plans in 2012; planned refractures and recompletions in 2012; expected use of proceeds from our Permian divestiture; the expected benefit of operational diversity in the Rocky Mountain region; our ability to mitigate risks by sharing costs of exploratory drilling in the Marcellus Shale with our joint venture partner; our intent to mitigate risks by maintaining a natural gas and liquids mix to counter a decline in the market price of one of our commodities; our expected term for inventory of projects for drilling activity; planned limited development in Piceance in 2012 due to the commodity pricing environment; drilling plans in the Utica Shale in 2012; that development drilling will remain the foundation of our drilling program; addition of 8 Bcfe of reserves at December 31, 2011 from the Seneca Upshur acquisition; our belief that pricing provisions in our natural gas contracts are customary; our belief that our exploration program has the potential to replenish our portfolio with new projects for significant production and reserves growth; our compliance with our debt covenants and the indenture restrictions governing our senior notes and expected continued compliance; sufficient liquidity to meet our partnership repurchase obligations; our belief that the acquisition of partnerships will provide us with growth in production and proved reserves and operational benefits; the adequacy of our casualty insurance coverage as managing general partner of numerous partnerships and as operator of our own wells; the impact of decreased commodity prices on future borrowing base redeterminations; that we hold good and defensible title to our natural gas and crude oil properties in accordance with industry standards; the effectiveness of our derivative

1



policies in achieving our risk management objectives; our expected remaining liability for uncertain tax positions; our ability to secure a joint venture partner for our Utica Shale acreage; the impact of outstanding legal issues; our ability to benefit from crude oil and natural gas price differential; and our 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 fiscal terms and/or regulations, including changes in environmental laws, the regulation and enforcement related to those laws and the costs to comply with those laws, as well as other regulations;
decline 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;
the potential for production decline rates from our wells to be greater than expected;
the timing and extent of our success in discovering, acquiring, developing and producing reserves;
our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;
the timing and receipt of necessary regulatory permits;
risks incidental to the drilling and operation of natural gas and crude oil wells;
our future cash flow, liquidity and financial position;
competition in the oil and gas industry;
the availability and cost of capital to us;
reductions in the borrowing base under our credit facility;
the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;
our success in marketing natural gas, NGLs and crude oil;
the effect of natural gas and crude oil derivatives activities;
the impact of environmental events, governmental responses to the events and our ability to insure adequately against such events;
the cost of pending or future litigation;
our ability to retain or attract senior management and key technical employees; and
the 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 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

Effective July 15, 2010, Petroleum Development Corporation began conducting business as PDC Energy. A new logo and corporate identity accompanied this change. Our common stock continues to trade on the NASDAQ Global Select Market under the ticker symbol PETD. We continue to maintain our website address, www.petd.com, which reflects the new PDC Energy name and brand identity. This change reflects the transitioning in our business model, from a company that was predominately a sponsor of limited partnerships to an exploration and production company that explores for and acquires, develops, produces and markets natural gas and oil resources.

We are a domestic independent exploration and production company that acquires, develops, explores, and produces natural gas, NGLs, and crude oil. Our Western Operating Region is primarily focused on development in the Wattenberg Field in Colorado, particularly in the liquid-rich horizontal Niobrara play and on the ongoing development of refractures and recompletions of our Wattenberg wells. In our Eastern Operating Region, we are focused on horizontal development in the Marcellus Shale in northern West Virginia, and recently initiated exploration and development activity in the liquid-rich portion of the Utica Shale play in Ohio. We own an interest in approximately 6,500 gross producing wells and maintained an average December 2011 production rate of approximately 146 MMcfe per day, which was comprised of 62% natural gas, 27% crude oil and 11% NGLs.

As of December 31, 2011, an independent petroleum engineering firm estimated our total proved reserves to be approximately 1

2



Tcfe with a PV-10%, a non-U.S. GAAP financial measure, of $1.3 billion. Approximately 46% of our total proved reserves have been classified as proved developed. Our total proved reserves consist of 66% natural gas and 34% crude oil and NGLs. Our internal estimate of proved, probable and possible ("3P") reserves has increased from 1.4 Tcfe as of December 31, 2010, to 2.1 Tcfe as of December 31, 2011, and includes a significant multi-year inventory of horizontal and vertical drilling projects as well as multiple refracture and recompletion projects in existing wells.

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.

2011 Overview
In 2011, we focused primarily in the liquid-rich Wattenberg Field in northern Colorado where we drilled 17 horizontal Niobrara wells, 80 vertical wells, completed 190 refracture and/or recompletion projects and participated in 48 non-operated drilling projects. During the year, we reduced our drilling of vertical wells to refocus our efforts on our horizontal Niobrara drilling program. We have successfully de-risked much of the horizontal Niobrara potential throughout our core Wattenberg acreage position and generated over 350 gross horizontal well projects in inventory. PDCM drilled six horizontal Marcellus wells, completed five horizontal wells and initiated several midstream projects. In October, we announced that we entered the Utica Shale play, where we have the rights to acquire up to an estimated 40,000 net acres targeting the wet gas and crude oil windows in southeast Ohio, and through PDCM, completed the Seneca-Upshur acquisition which added 90,000 gross acres to our Marcellus position. During the fourth quarter, we closed on the sale of our non-core Permian Basin assets to an unrelated third party for a sales price of $13.2 million. In December, we executed a definitive agreement to sell our core Permian Wolfberry assets to another unrelated third party for a sales price of $173.9 million, subject to customary post-closing adjustments. On February 28, 2012, this divestiture was completed with total proceeds received of $184.4 million after preliminary closing adjustments.
.
Business Strategy

Our business strategy focuses on generating shareholder value through the growth of our reserves and production in our liquid-rich and high impact horizontal plays. We allocate capital to high return projects in our portfolio capable of maximizing our cash flow and return on capital. We place a strong emphasis on organic growth through active horizontal drilling programs, emphasize low-risk development drilling, engage in targeted exploratory drilling in 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 consists primarily of interests in developed and undeveloped natural gas, NGLs and crude oil resources located in our Western and Eastern Operating Regions. We seek to maximize the value of our existing wells through a successful program of well refractures, recompletions and workovers. Based on our prior acreage holdings and recent acquisitions, we have accumulated a multi-year inventory of horizontal and vertical developmental drilling projects, as well as refracture, recompletion and exploration projects.
 
Western Operating Region. Our primary focus in the liquid-rich Wattenberg Field is horizontal development drilling of the Niobrara formation. We also maintain a vertical drilling inventory in the Niobrara and Codell formations in Wattenberg and continue to execute on multiple refracture and recompletion projects. Additionally, we operate natural gas assets in the Piceance Basin in western Colorado and in northeast Colorado ("NECO") where we currently focus on production optimization and increasing operating margins.
 
Approximately 65% of our 2012 capital budget, or $184 million, is expected to be spent on development activities, approximately 97% of which is expected to be invested in the Wattenberg Field for an expanded horizontal Niobrara drilling program, increased pace of refractures and recompletions and participation in various non-operated projects. We currently estimate that we have more than 1,750 gross drilling projects, which include over 350 gross projects for the horizontal Niobrara, and approximately 1,450 refracture and recompletion projects in existing wells in the Wattenberg Field. Depending on the number of drilling rigs operating and commodity prices, we believe that this inventory of projects provides us with approximately 10 years of drilling activity. In 2012, we plan to run a one-rig program in Wattenberg to drill between between 25 and 30 horizontal Niobrara wells, along with completing an estimated 250 to 265 refracture and recompletion projects on existing wells.
 
In 2011, we drilled a total of 17 development wells in the Piceance Basin. We currently estimate that we have more than 390 gross drilling projects, representing multiple years of inventory depending on the number of drilling rigs operating and commodity prices. We expect to maintain a disciplined approach to the development of our Piceance gas acreage holdings in 2012, with plans to complete only those wells previously drilled in this area in 2011 as we focus our capital budget in areas expected to generate higher rates of return.

Drilling activity in the Permian Basin in 2011 included 23 development wells, including two determined to be dry holes. In October 2011, we announced our intent to divest our Permian Basin assets. The divestiture was completed on February 28, 2012. See Acquisitions and Divestitures below and Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets.
 
Eastern Operating Region. Our primary focus in the Marcellus Shale natural gas play consists of horizontal drilling in West Virginia. In 2011, PDCM drilled a total of 6 gross, 3 net, horizontal wells and constructed various midstream assets to gather and compress its Marcellus gas. PDCM recently announced it has elected to temporarily suspend drilling in the Marcellus Shale play due to the current depressed natural gas price environment. Prior to suspending its drilling activities in 2012, PDCM expects to drill a total of 4 gross horizontal

3



wells and complete 7 wells, including 3 wells that were in-process as of December 31, 2011.
 
With the addition of our Ohio leaseholds in late 2011, we have recently begun to focus on exploratory and delineation drilling targeting the wet gas and crude oil windows of the Utica Shale. We drilled one vertical well to total depth in mid-December, which was fracture treated early in 2012. In 2012, we expect to drill approximately two horizontal shale wells with an option to drill two additional vertical wells. Currently, we are pursuing an industry joint venture partner to participate in and share in funding the growth and development in this play. While we expect to identify a partner by mid-2012, we cannot assure we will be successful in securing a partner or developing this acreage.

The following table presents information regarding the number of wells we drilled or participated in and the number of refractures and/or recompletions we performed.

 
 
Drilling Activity
 
 
Year Ended December 31,

 
2011
 
2010
 
2009
Operating Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Western (1)
 
186


139.6


204


164.9


92


71.2

Eastern
 
9

 
5.2

 
9

 
5.2

 
8

 
8.0

Total wells drilled
 
195

 
144.8

 
213

 
170.1

 
100

 
79.2

Refractures and Recompletions (2)
 
192

 
177.6

 
46

 
33.7

 
37

 
35.4

 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(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 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets.
(2)
190 of the refractures and recompletions 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,
 
 
2011
 
2010
 
2009
Operating Region/Area
 
Productive
 
In-Process
 
Dry
 
Productive
 
In-Process
 
Dry
 
Productive
 
In-Process
 
Dry
Western
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
86.5

 
13.1

 

 
106.9

 
26.5

 

 
58.3

 
6.9

 

Piceance Basin
 
14.0

 
3.0

 

 
18.0

 
7.0

 

 
1.0

 

 

Permian Basin (1)
 
14.5

 
5.5

 
2.0

 

 
5.0

 

 

 

 

Other
 

 

 

 
0.5

 

 

 
2.0

 

 
1.0

Total Western
 
115.0

 
21.6

 
2.0

 
125.4

 
38.5

 

 
61.3

 
6.9

 
1.0

Eastern
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
 
0.9

 
2.0

 

 
0.6

 
1.1

 

 
2.0

 

 

Total Eastern
 
0.9

 
2.0

 

 
0.6

 
1.1

 

 
2.0

 

 

Total net development wells
 
115.9

 
23.6

 
2.0

 
126.0

 
39.6

 

 
63.3

 
6.9

 
1.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(1)
As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets.


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Net Exploratory Well Drilling Activity
 
 
Year Ended December 31,

 
2011
 
2010
 
2009
Operating Region/Area
 
In-Process
 
Productive
 
In-Process
 
Productive
 
In-Process
Western
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 

 

 
1.0

 

 

Other
 
1.0

 

 

 
1.0

 
1.0

Total Western
 
1.0

 

 
1.0

 
1.0

 
1.0

Eastern
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
 
2.3

 
2.8

 
0.7

 
5.0

 
1.0

Total Eastern
 
2.3

 
2.8

 
0.7

 
5.0

 
1.0

Total net exploratory wells
 
3.3

 
2.8

 
1.7

 
6.0

 
2.0

 
 
 
 
 
 
 
 
 
 
 


Acquisitions and Divestitures
 
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. As we evaluate investment opportunities, we may also seek to divest non-core assets to optimize our property portfolio.
 
Acquisitions
 
In 2010, we initiated a plan to purchase our affiliated partnerships. 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. We believe that these acquisitions will also allow us to realize operational benefits as well as the potential to accelerate the refracture/recompletion program of the wells acquired, thus allowing us to optimize revenue opportunities. As of December 31, 2011, we had acquired a total of 12 affiliated partnerships for an aggregate purchase price of $107.7 million, eight of which occurred in 2011 for an aggregate purchase price of $73 million. We estimate that the 2011 acquisitions added approximately 40 Bcfe in total proved reserves as of December 31, 2011, which includes the non-affiliated investor partners' remaining working interests in a total of 299 gross, 204.2 net, wells located in our Wattenberg Field and Piceance Basin.
 
During 2011, we obtained the rights to acquire Utica leasehold acres from unrelated third parties targeting the wet natural gas and crude oil windows of the Utica Shale play throughout southeastern Ohio. Should we exercise our right to acquire all 40,000 acres, we estimate that the purchase price of such leaseholds will approximate $70 million. A portion of the options related to these leaseholds will expire in August 2012. Currently, we are pursuing an industry joint venture partner to participate in and share in funding the growth and development in this play. While we expect to identify a partner by mid-2012, we cannot assure we will be successful in securing a partner or developing this acreage.
 
In October 2011, PDCM acquired from an unrelated third party 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur"), a West Virginia limited liability company, for the purchase price of $162.9 million, including a post-closing working capital adjustment of $10.4 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, prospective for the Marcellus Shale 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 $81.5 million and we hold a 50% interest in both the wells and acreage acquired. We estimate that the acquisition added approximately 8 Bcfe to our total proved reserves as of December 31, 2011.

Divestitures
    
Permian Basin. In October 2011, we announced our intent to divest our acreage located in the Wolfberry Trend in the Permian Basin in West Texas to focus our efforts in our horizontal drilling programs and to provide funding for our 2012 capital budget. During the fourth quarter of 2011, we completed the sale of our 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. The transaction closed on February 28, 2012 with total proceeds received of $184.4 million after preliminary closing adjustments. The proceeds from the sales were used to pay down our corporate credit facility, until needed to fund our 2012 capital budget. The Permian Basin assets were classified as held for sale as of December 31, 2011 and 2010, and the results of operations related to those assets were reported as discontinued operations in 2010, year of acquisition, and 2011 on our consolidated statements of operations included in this report.
 
North Dakota. In December 2010, we effected a letter of intent with an unrelated third party for the sale of our North Dakota assets. The North Dakota assets were classified as held for sale as of December 31, 2010, and the results of operations related to those assets were reported as discontinued operations in 2009, 2010 and 2011 on our consolidated statements of operations included in this report. In February

5



2011, we executed a purchase and sale agreement and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million, net of non-affiliated investor partners' share of $3.8 million, resulting in a pretax gain on sale of $3.9 million.
    
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 leaseholds we acquired targeting the Utica Shale meet these criteria and we see these leaseholds as our primary exploration play for 2012.

Manage Operational and Financial Risk

We focus on lower risk development drilling programs in resource plays with repeatable drilling opportunities that will grow reserves and production while maintaining or growing cash flows. We regularly review acquisition opportunities in our core areas of operation as we believe we can enhance the value of such opportunities through economies of scale. We believe development drilling will remain the foundation of our drilling programs; however, we view a disciplined approach to exploratory drilling as having the potential to identify new development opportunities, as we have done in recent years with our horizontal Niobrara and Marcellus drilling programs.

We engage in limited exploratory drilling as such activities involve numerous risks, including the risk that we may not be successful in the discovery of commercially productive natural gas and crude oil reservoirs. Costs associated with exploratory activities can be quite high. In an effort to mitigate in part the financial risk associated with exploratory activities, we may seek opportunities to participate in joint venture arrangements to share in the potential high costs and risks of exploratory drilling while maximizing the potential returns. We believe our Marcellus JV has effectively served to mitigate the risks associated with exploring the Marcellus Shale. We are currently seeking an investment partner to participate with us in exploring our newly acquired Ohio properties, which are prospective for the wet gas and crude oil windows of the Utica Shale. We cannot assure we will be successful in securing a joint venture partner or developing this acreage.
    
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 65% natural gas to 35% liquids. While our legacy properties in the Eastern Operating Region primarily produce natural gas, our Ohio properties are prospective for 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 portion of our exposure to price volatility with regard to our natural gas and crude oil sales and natural gas marketing. We utilize both financial and physical derivative instruments. The financial instruments consist of floors, collars, swaps and basis swaps and consist of NYMEX, CIG and PEPL-based contracts. We may utilize derivatives based on other indices or markets where appropriate. The contracts provide price stability for up to 80% of our committed and anticipated natural gas and crude oil sales and purchases forecasted to occur within the next five-year period. Our policies prohibit the use of commodity derivatives for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. As of December 31, 2011, we had natural gas and crude oil derivative positions in place for 2012 covering 59.1% of our expected natural gas production and 60.8% of our expected crude oil production. Currently, we do not hedge our NGL production. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for a detailed summary of our open derivative positions.

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

Business Segments

We divide our operating activities into two segments: (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 sell our natural gas to marketers, utilities, industrial end-users and other wholesale purchasers. We primarily 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, quality of natural gas and prevailing supply and demand conditions. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of

6



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.

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.

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.

We enter into financial derivatives in order to reduce the impact of possible price volatility regarding the physical sales market. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations: Results of Operations – Commodity Price Risk Management, Net, Natural Gas and Crude Oil Derivative Activities, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, and Note 4, Derivative Financial Instruments, to our consolidated financial statements included 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 and NGLs are 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 on the volume and distance shipped, and the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally interrupted due to repairs or improvements. A majority of our natural gas is transported under interruptible contracts and thus could, if pipeline space is constrained, result in an interruption in natural gas sales. 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 cash flow from the affected properties could be adversely affected. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our 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 Piceance Basin and the NECO areas 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. These agreements are subject to the same limitations discussed above in this paragraph. See Note 11, Commitments and Contingencies - Firm Transportation Agreements, to our consolidated financial statements included in this report for our long-term firm sales, processing and transportation agreements for pipeline capacity.

Our crude oil production is marketed directly to purchasers in the Wattenberg 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 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, 2011.
    
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, as well as 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 17, Business Segments, to our consolidated financial statements included in this report.


7



Areas of Operations

The following map presents the general locations of our development, production and exploration activities as of December 31, 2011. 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.



Western Operating Region

Our primary focus in the Western Operating Region for 2012 and the near term is on horizontal Niobrara drilling. We divide our Western Operating Region into two major areas: the Wattenberg Field and Piceance Basin.

Wattenberg Field, DJ Basin, Colorado. Wells drilled in this area have historically been vertical and range from approximately 7,000 to 8,000 feet in depth. These wells target reservoirs in the Codell and Niobrara formations that have historically contained about 50% crude oil and NGLs. In October 2010, we began a horizontal drilling program targeting the liquid-rich Niobrara formation. The horizontal Niobrara wells have a vertical depth range from approximately 7,000 to 8,000 feet with an average lateral length of 4,000 feet. Operations in Wattenberg Field, in addition to developmental drilling, include a program of refractures and recompletion projects on existing wells in the Codell and Niobrara reservoirs.

Piceance Basin, Colorado. Wells in this area predominately target natural gas, with the area's volume of natural gas reserves representing approximately 47% of our total proved natural gas reserves, which equates to approximately 32% of our total proved reserves. Reserves in this area represent approximately 1% of our present value of future net revenues ("PV-10%"), a non-U.S. GAAP measure. See table in the Properties -Proved Reserves section below for information regarding our proved reserves and PV-10% as of December 31, 2011. While 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, 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.

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.

Northeastern Colorado ("NECO"). Wells drilled in this are range from 1,500 to 3,000 feet in depth and target natural gas reserves in the shallow Niobrara reservoir. We have not conducted drilling activity in this area since 2009.

Permian Basin. As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets.

Eastern Operating Region

Our primary focus in the Eastern Operating Region is on horizontal drilling in the Marcellus Shale play in northern West Virginia and, with the addition of leaseholds in Ohio during 2011, exploratory and delineation drilling in the emerging Utica Shale play.
    

8



Marcellus Shale, West Virginia. In October 2009, through our contribution of the majority of our Eastern Operating Region assets, consisting of acreage, producing properties and related reserves, gathering assets and equipment, and a cash contribution by our joint venture partner, we formed the joint venture PDCM. The wells contributed were producing from the shallow Devonian and Mississippian aged tight sandstone reservoirs, ranging from 1,200 to 6,000 feet in depth. In October 2011, PDCM acquired all rights and depths to 100,000 net acres, of which 90,000 net acres are prospective for the Marcellus Shale and added an additional 1,340 gross wells producing from the Devonian and Mississippian formations. PDCM is primarily focused on horizontal drilling, targeting the Marcellus Shale formation in northern West Virginia. 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 311 gross, 106.2 net, natural gas and crude oil wells in West Virginia, Pennsylvania and Tennessee.

Utica Shale, Ohio. Our newest prospect is the Utica Shale play in southeastern Ohio, with our initial leasehold acquisitions occurring in 2011. Exploratory drilling activity began in the fourth quarter, with one vertical well drilled to total depth, approximately 9,600 feet, and subsequently fracture treated in early 2012. We continue to pursue an industry joint venture partner to participate in and share in funding the growth and development in this play; however, we cannot assure we will be successful in securing a partner or developing the play.
    
Properties

Productive Wells

The following table presents our productive wells.

 
 
Productive Wells
 
 
As of December 31, 2011
 
 
Natural Gas
 
Crude Oil
 
Total
Operating Region/Area
 
Gross
 
 Net 
 
 Gross
 
 Net
 
 Gross
 
 Net
Western
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
1,762

 
1,456.0

 
24

 
19.1

 
1,786

 
1,475.1

Piceance Basin
 
348

 
301.4

 

 

 
348

 
301.4

Permian Basin (1)
 

 

 
58

 
54.5

 
58

 
54.5

NECO
 
618

 
410.0

 

 

 
618

 
410.0

Other
 
97

 
95.0

 
3

 
0.7

 
100

 
95.7

Total Western
 
2,825

 
2,262.4

 
85

 
74.3

 
2,910

 
2,336.7

Eastern
 
 
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
 
3,568

 
1,652.4

 
39

 
15.5

 
3,607

 
1,667.9

Total Eastern
 
3,568

 
1,652.4

 
39

 
15.5

 
3,607

 
1,667.9

Total productive wells
 
6,393

 
3,914.8

 
124

 
89.8

 
6,517

 
4,004.6

 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(1)
As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets.

Proved Reserves

Our proved reserves are sensitive to future natural gas and crude oil sales prices and their 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 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. All of our proved reserves, as of December, 31, 2011, 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 review includes, but is not limited to, confirmation that reserve estimates (1) include all properties owned, (2) are based on proper working and net revenue interests, and (3) reflect reasonable cost estimates and field performance. The internal team compiles the reviewed data and forwards the data to an independent engineering firm engaged to estimate our reserves.

9




Our reserve estimates as of December 31, 2011, were based on a reserve report prepared by Ryder Scott Company, L.P. ("Ryder Scott"). When preparing our reserve estimates, the independent petroleum engineer did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices, or any agreements relating to current and future operations of properties and sales of production.
 
The independent petroleum engineer 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. The final independent petroleum engineer's 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 and has over 30 years of experience in reservoir engineering. The individual 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 following tables provide information regarding our estimated proved reserves. Reserves cannot be measured exactly, because reserve estimates involve judgments. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure 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 in this report.

 
As of December 31,
 
2011 (1)
 
2010 (1)
 
2009
Proved reserves
 
 
 
 
 
Natural gas (MMcf) (2)
672,145

 
657,306

 
608,925

Crude oil and condensate (MBbls)
37,636

 
23,236

 
18,070

NGLs (MBbls) (2)
19,588

 
10,649

 

Total proved reserves (MMcfe)
1,015,489

 
860,616

 
717,345

Proved developed reserves (MMcfe) (3)
471,347

 
301,141

 
295,839

Estimated future net cash flows (in millions)
$
2,290

 
$
1,315

 
$
764

PV-10% (in millions) (4)
$
1,350

 
$
693

 
$
360

Standardized measure (in millions)
$
941

 
$
488

 
$
348

__________
(1)
Includes estimated reserve data related to our Permian assets, which were held for sale as of December 31, 2011, and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included 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


(2)
Prior to 2010, NGLs were included in natural gas, which impacts comparability of 2011 and 2010 to 2009.
(3)
Approximately 73.4% 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 proved undeveloped to proved developed as a result of the greater difference between the cost of a refracture and the cost of drilling a new well.
(4)
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, nor is it 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.

10



GAAP Financial Measures, for a definition of PV-10% and a reconciliation of our PV-10% value to the standardized measure.


 
 
As of December 31, 2011
Operating Region/Area
 
Natural Gas
(MMcf)
 
NGLs
(MBbls)
 
Crude Oil and Condensate (MBbls)
 
Natural Gas
Equivalent
(MMcfe)
 
Percent
Proved developed
 
 
 
 
 
 
 
 
 
 
Western
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
113,911

 
11,203

 
14,788

 
269,857

 
58
%
Piceance Basin
 
108,642

 

 
231

 
110,028

 
23
%
Permian Basin (1)
 
1,750

 
550

 
1,815

 
15,940

 
3
%
Other
 
31,940

 

 

 
31,940

 
7
%
Total Western
 
256,243

 
11,753

 
16,834

 
427,765

 
91
%
Eastern
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
 
43,126

 

 
76

 
43,582

 
9
%
Total Eastern
 
43,126

 

 
76

 
43,582

 
9
%
Total proved developed
 
299,369

 
11,753

 
16,910

 
471,347

 
100
%
Proved undeveloped
 
 
 
 
 

 
 
 
 
Western
 
 
 
 
 

 
 
 
 
Wattenberg Field
 
64,071

 
6,414

 
14,506

 
189,591

 
35
%
Piceance Basin
 
210,467

 

 
210

 
211,727

 
39
%
Permian Basin (1)
 
4,492

 
1,421

 
6,010

 
49,078

 
9
%
Other
 
3,194

 

 

 
3,194

 
*

Total Western
 
282,224

 
7,835

 
20,726

 
453,590

 
83
%
Eastern
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
 
90,552

 

 

 
90,552

 
17
%
Total Eastern
 
90,552

 

 

 
90,552

 
17
%
Total proved undeveloped
 
372,776

 
7,835

 
20,726

 
544,142

 
100
%
Proved reserves
 
 
 
 
 
 
 
 
 
 
Western
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
177,982

 
17,617

 
29,294

 
459,448

 
46
%
Piceance Basin (2)
 
319,109

 

 
441

 
321,755

 
32
%
Permian Basin (1)
 
6,242

 
1,971

 
7,825

 
65,018

 
6
%
Other
 
35,134

 

 

 
35,134

 
3
%
Total Western
 
538,467

 
19,588

 
37,560

 
881,355

 
87
%
Eastern
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
 
133,678

 

 
76

 
134,134

 
13
%
Total Eastern
 
133,678

 

 
76

 
134,134

 
13
%
Total proved reserves
 
672,145

 
19,588

 
37,636

 
1,015,489

 
100
%
 
 
 
 
 
 
 
 
 
 
 
______________
* De Minimis
    
(1)
As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets.
(2)
Two leases in our Piceance Basin represent 32% of our total proved reserves.


11



Developed and Undeveloped Acreage

The following table presents our developed and undeveloped lease acreage.
 
 
As of December 31, 2011
 
 
Developed
 
Undeveloped (1)
 
Total
Operating Region/Area
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Western
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
53,300

 
51,200

 
28,800

 
20,200

 
82,100

 
71,400

Piceance Basin
 
3,100

 
3,100

 
4,900

 
4,900

 
8,000

 
8,000

Permian Basin (2)
3,800

3,800

 
3,400

 
6,800

 
6,500

 
10,600

 
9,900

NECO
 
23,600

 
19,600

 
81,500

 
71,700

 
105,100

 
91,300

Other
 
400

 
400

 
22,100

 
18,000

 
22,500

 
18,400

 Total Western
 
84,200

 
77,700

 
144,100

 
121,300

 
228,300

 
199,000

Eastern
 
 
 
 
 
 
 
 
 
 
 
 
Appalachian Basin
 
263,900

 
107,300

 
50,000

 
33,150

 
313,900

 
140,450

Total Eastern
 
263,900

 
107,300

 
50,000

 
33,150

 
313,900

 
140,450

 Total acreage
 
348,100

 
185,000

 
194,100

 
154,450

 
542,200

 
339,450

 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(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 15% of our undeveloped leaseholds expire during 2012, none of which is material to any one specific area. 
(2)
As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets.

Title to Properties

We believe that we hold good and defensible 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 conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties.

The properties we own are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The properties may also be subject to additional burdens, liens or encumbrances customary to the industry, including items such as operating agreements, current taxes, development obligations under natural gas and crude oil leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties.

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

Facilities

We lease 39,720 square feet 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
Texas: Midland
West Virginia: Bridgeport, Buckhannon and Glenville

Governmental Regulation

While the prices of natural gas and crude oil are market driven, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for natural gas and crude oil production depends on several factors beyond our control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of

12



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, to reduce environmental and health risks from the development and transportation of natural gas and crude oil, to prevent misuse of natural gas and crude oil and to 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 orders to which our operations may be subject.

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

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

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.

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

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

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

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

costs of providing service, including depreciation expense;
allowed rate of return, including the equity component of the capital structure and related income taxes; and

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volume throughput assumptions.

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

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

Environmental Matters

Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and 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 such as shales that generally exist between 4,000 and 14,000 feet below ground. We routinely apply fracturing in our drilling 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 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. Also, 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 record keeping and reporting for all flowback and produced water; and restrictions on well locations. In Ohio, in early 2012, officials of the 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.

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,

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with initial results expected to be available by late 2012 and final results 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 considering disclosure requirements or 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 mechanism.

In Colorado, local governing bodies have begun to issue drilling moratoriums or develop jurisdictional siting, permitting, and operating requirements. 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 oil and natural gas that we are ultimately able to produce from its 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 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 introduced by the EPA in 2011 will become effective in 2012, adding administrative and operational expense.

The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants, including spills and leaks of crude oil and other substances. The CWA also regulates storm water run-off from natural gas and crude oil facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls and piping controls 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 SPCC plans relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990, or OPA, subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. 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.
    
In late 2011, the State of Colorado's Oil and Gas Conservation Commission ("Commission") adopted rules that require service companies and vendors to disclose all known chemicals in hydraulic fracturing fluid to operators and require operators to disclose such chemicals to the public through a website or, with respect to an operator's trade secrets, directly to the Commission or health professionals. 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. These regulations will continue to increase our costs and may ultimately limit some drilling locations.

Our expenses relating to preserving the environment have risen over the past few years and are expected to continue to rise in 2012

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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 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 whether insurance will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third party property, such as 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, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We also face intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic natural gas and crude oil exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties will increase in the future.

In 2011, certain regions experienced strong demand for drilling services and supplies, which resulted in increasing costs. Our Wattenberg Field and Eastern Operating Region, specifically our properties in West Virginia, 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 position, results of operations and cash flows could be materially adversely affected.

Employees

As of December 31, 2011, we had 404 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.



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ITEM 1A. RISK FACTORS

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

Risks Related to the Domestic and Global Economic Environment

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

The global financial market disruptions during the recent recession and the related economic environment initially resulted in a decrease, and more recently in 2011, limited growth in the demand for natural gas and crude oil and has maintained pressure on natural gas prices. For example, during 2011, the price for natural gas decreased another 8% from 2010 rates, which were over 60% below the 2008 peak. Crude oil prices rebounded in 2011, increasing 20% over 2010 rates, but were still 28% below the 2008 peak. While crude oil prices have remained relatively strong, the continued growth in production of natural gas has increased supply and resulted in record gas storage inventories. As a result natural gas prices continue to face downward pressure. There is no certainty how long this low price environment would continue. We operate in a highly competitive industry, and certain competitors may have lower operating costs in such an environment. In particular, consider the risks related to (1) the deterioration of demand for natural gas and crude oil products and the related negative impact on natural gas and crude oil pricing, and (2) the deterioration of the financial markets and the related challenges, constraints or inability to raise necessary capital or maintain sufficient liquidity to access and provide the capital necessary to fund our operations. Further reductions in natural gas and crude oil prices could result in some of our assets becoming uneconomic to exploit, which would reduce our economically viable reserve profile. Counterparty failure risk would increase for both the banks which provide us capital and are parties to our natural gas and crude oil derivative holdings and for purchasers of our natural gas and crude oil. A prolonged and material negative economic environment could lead to the curtailment of capital expenditures and therefore a reduction in our drilling program, which would result in reduced production, reserves, cash flow generation and financial results.

Credit and funding challenges of French banks which are participants in our revolving credit facility and counterparties to some of our natural gas and crude oil derivative holdings could have a material adverse effect on our operations and financial condition.

We have three French banks, Credit Agricole Corporate and Investment Bank ("CA"), BNP Paribas ("BNP") and Natixis (collectively "the French Banks") that participate in our revolving credit facility and are counterparties to some of our natural gas and crude oil derivative hedges. The recent global economic turmoil, particularly in Europe, has led to negative credit actions and created an increased cost for the French Banks to provide U.S. dollar funding under contractually committed U.S. credit facilities. Certain of the French Banks have provided public disclosures as to the challenges they are experiencing. BNP has announced that it plans to divest both its U.S. hedging holdings and activities and its U.S. dollar energy portfolio; CA has announced that it is divesting its U.S. hedging holdings and activities. We are unaware of any announced divestitures by Natixis. We have had numerous discussions with senior bank representatives from each of the French Banks, and their representatives have indicated they plan to hold their current position in our revolving credit facility and intend to fund borrowing requests as contractually required. Additionally, the French Banks have indicated that they intend to satisfy their contractual counterparty obligations on all natural gas and crude oil derivative holdings with us. Moreover, the French Banks have been performing to date under our revolving credit facility and as hedging counterparties. However, should the need arise, we believe we would be able to replace our current French Banks borrowing and hedging capacity through increased credit provision from our existing bank syndicate or through the addition of additional banks to our bank syndicate. In light of the preceding challenges confronting our French bank credit providers, and despite the numerous mitigants to offset the situation, we cannot assure that we can replace the borrowing capacity being provided to us by the French Banks should the need arise, or that the French Banks will continue to perform under our revolving credit facility or as hedging counterparties in the future. Should we be unable to replace such borrowing capacity, or should the French Banks fail to perform, those events could have a material adverse effect on our operations and financial condition.

While we believe that we will be able to find other banking institutions to be effective counterparties for our derivatives instruments in the future, it is possible that the loss of these banks from the class of available banking institutions that become counterparties for U.S. derivative instruments will significantly reduce the number of banking institutions that write such instruments and serve as counterparties. In this event, it is possible that we might not be able to find comparable counterparties to write derivatives instruments as readily as before these banks determined to leave the U.S. hedging market. Additionally, even if we are readily able to contract with such counterparties, the cost of these derivatives instruments might be greater than those that we have to date become a party to, thereby diminishing the economic effectiveness of those derivatives instruments that we in fact do write. Moreover, it is possible that with new counterparties to our derivatives instruments the risk of counterparty default on such derivatives instruments might increase.
Risks Related to Our Business and the Industry

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

Our revenue, profitability and cash flow depend in large part upon the prices and demand for natural gas and crude oil. The markets

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for these commodities can be volatile, and significant drops in prices can negatively affect our financial results and impede our growth. For instance, in much of 2011, natural gas prices were too low to economically justify drilling operations in several areas. Changes in natural gas and crude oil prices have a significant effect on our cash flow and on the value of our reserves, which can in turn reduce our borrowing base under our senior credit facility. Prices for natural gas and crude oil may fluctuate in response to relatively minor changes in the supply of and demand for natural gas and crude oil, market uncertainty and a variety of additional factors that are beyond our control, including national and international economic and political factors and federal and state legislation. In addition to factors affecting the price of oil and natural gas generally, the prices we receive for our oil and natural gas 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. In addition, any substantial reduction in the growth rate of China could affect global oil prices significantly.

Lower natural gas and crude oil prices may not only reduce our revenues, but also may reduce the amount of natural gas and crude oil that we can produce economically. As a result, we may have to make substantial additional downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write-down operating assets to fair value, as a non-cash charge to earnings. We assess impairment of capitalized costs of proved natural gas and crude oil properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products may be sold. In 2011 and 2010, we recorded an impairment charge related to our NECO proved natural gas and crude oil properties of $22.5 million and related to our Michigan proved natural gas and crude oil properties an impairment of $4.7 million, respectively. These impairments were attributable to our decision to divest these assets. We may incur impairment charges in the future, which could have a material adverse effect on the results of our operations.

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 on usage may lead to water constraints and supply concerns. 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 regulations 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 CWA imposes restrictions and strict controls regarding the discharge of produced waters and other oil and natural gas waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar 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. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Indeed, on October 20, 2011, the EPA announced its intention to develop federal pretreatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the new 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 and 2014 for shale gas. We cannot predict the impact that these standards may have on our business at this time, but these standards could have a material impact on our business, financial condition and results of 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 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.

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

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

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the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The initial results are expected in the fall of 2012.

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

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

Our operations have been focused in the Wattenberg Field and Piceance Basin of 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 and crude oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells. For example, the recent increase in activity in the Niobrara could lead to bottlenecks in processing that negatively affect our results disproportionately compared to our more geographically diverse competitors.
    
Prior to 2010, natural gas prices in the Rocky Mountain Region often fell disproportionately when compared to other markets, due in part to continuing constraints in transporting natural gas from producing properties in the region. Because of the concentration of our operations in our Western Operating Region, such price decreases are more likely to have a material adverse effect on our revenue, profitability and cash flow than those of our more geographically diverse competitors. During 2010 and 2011, natural gas prices in the Rocky Mountain Region were not steeply discounted to NYMEX and future prices are trading at the same discount; however, there can be no assurance as to such continuation. In view of the concentration of our operations in Colorado, a significant decline in natural gas prices in the Western Operating Region could have a material adverse effect on our operations, financial condition and results of operations.

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

Natural gas and crude oil reserve engineering requires subjective estimates of underground accumulations of natural gas and crude oil and assumptions concerning natural gas and crude oil prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of natural gas and crude oil reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding natural gas and crude oil prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect:
the economically recoverable quantities of natural gas and crude oil attributable to any particular group of properties;
future depreciation, depletion and amortization ("DD&A") rates and amounts;
impairments in the value of our assets;
the classifications of reserves based on risk of recovery;
estimates of the future net cash flows;
timing of our capital expenditures; and
the amount of funds available for us to utilize under our revolving credit facility.

Some of our reserve estimates must be made with limited production history, which renders these reserve estimates less reliable than estimates based on a longer production history. 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 will be different than the reserve estimates since they will 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.

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 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

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

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

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

Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, 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 natural gas and crude oil prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain, including those regarding the validity of our assumptions about reserves, future production, future commodity prices, revenues, capital expenditures and operating costs, including synergies. In connection with our assessments, we perform engineering, geological and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited.

The acquisitions of producing natural gas and crude oil properties may increase our potential exposure to liabilities and costs for environmental and other problems existing on acquired properties. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an "as is" basis with no or limited remedies for breaches of representations and warranties. We could incur significant unknown liabilities, including environmental liabilities, natural disasters or experience losses due to title defects, in our 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 efficiently realize the assumed or expected economic benefits of acreage that we acquire, if at all.

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

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

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 may be unable to make additional acquisitions of such affiliated drilling partnerships since consummation of any future acquisitions of our affiliated public drilling partnerships 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, two former non-affiliated investor partners have initiated litigation concerning our acquisition of the limited partnership units we acquired in 2010 and 2011. Litigation challenges to further acquisitions are also possible. If we are unable to consummate all or a portion of these prospective acquisitions, we would not realize the expected benefits of the proposed acquisitions. In addition, we will have incurred, and will remain liable for, transaction costs, including legal, accounting, financial advisory and other costs relating to the prospective acquisitions, including the costs of the financial and legal consultants to the special committee of our board of directors, whether

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or not they are consummated. We currently do not have any drilling partnership acquisitions pending or planned in 2012; however, future acquisitions are possible. The occurrence of any of these events individually or in combination could have an adverse effect on our business, financial condition and results of operations.

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

Even if we complete the prospective acquisitions, integration of the prospective acquisitions may be difficult. Any acquisition involves potential risks, including, among other things:
the validity of our assumptions about reserves, future production, future commodity prices,
revenues, capital expenditures and operating costs, including synergies;
an inability to integrate the businesses we acquire successfully;
a decrease in our liquidity by using a portion of our available cash or borrowing capacity under
our revolving credit facility to finance acquisitions;
a significant increase in our interest expense or financial leverage if we incur additional debt to
finance acquisitions;
the assumption of unknown liabilities, losses or costs, including those that are environmental, for
which we are not indemnified or for which our indemnity is inadequate;
the diversion of management’s attention from other business concerns;
the incurrence of other significant charges, such as impairment of natural gas and crude oil properties,
goodwill or other intangible assets, asset devaluation or restructuring charges;
unforeseen difficulties encountered in operating in new geographic areas; and
customer or key employee losses at the acquired businesses.

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

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

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

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

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

Drilling for and producing natural gas and crude oil are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. Our drilling risk exposure may be increased as we plan to  devote most of our 2012 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;
blowouts;
loss of drilling fluid circulation;
title problems;
facility or equipment malfunctions;
unexpected operational events;
shortages or delivery delays of equipment and services;

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compliance with environmental and other governmental requirements; and
adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. We maintain insurance against various losses and liabilities arising from operations; however, insurance against 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.

Our business strategy focuses on production in our liquid-rich and high impact shale gas plays.  In this regard, we plan to allocate our capital to an active horizontal drilling program.  During 2012, we intend to devote a substantial part of our capital budget to drilling horizontal wells in the Wattenberg Field in Colorado to exploit the Niobrara formation.  While we drilled 195 total wells in 2011, we plan to drill approximately 35 wells during 2012.  Substantially all of these wells will be horizontal wells.  Drilling horizontal wells is technologically more difficult than drilling vertical wells, and thus the risk of failure is far greater than the risk involved in drilling vertical wells.  Additionally, drilling horizontal wells is far costlier than drilling vertical wells.  Consequently, because we plan to drill far fewer wells during 2012, 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 previous 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 involved in drilling horizontal wells.  While we believe that the Company 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.                  

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

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

We have conducted exploratory drilling and plan to continue exploratory drilling in 2012 in order to identify additional opportunities for future development. Under the "successful efforts" method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period when they are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed and have a negative effect on our debt covenants.

Increasing finding and development costs may impair our profitability.

In order to continue to grow and maintain our profitability, we must annually add new reserves that exceed our yearly production at a finding and development cost that yields an acceptable operating margin and DD&A rate. Without cost effective exploration, development or acquisition activities, our production, reserves and profitability will decline over time. Given the relative maturity of most natural gas and crude oil basins in North America and the high level of activity in the industry, the cost of finding new reserves through exploration and development operations has been increasing. The acquisition market for natural gas and crude oil properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values for crude
oil properties climbed in 2010 and 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 carrying value of our crude oil properties in response to any future falling commodity prices and reduced profitability of our operations.

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

Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and crude oil reserves. To date, we have financed capital expenditures primarily with bank borrowings under our credit facility, cash generated by operations and capital markets, through the sale of equity and the issuance of debt securities and 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 and crude oil we are able to produce from existing wells;
the prices at which natural gas and crude oil are sold;

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the costs to produce natural gas and crude oil; and
our ability to acquire, locate and produce new reserves.

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

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

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

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

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

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

We operate approximately 88% of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology.

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

Market conditions or the unavailability of satisfactory natural gas and crude oil transportation arrangements may hinder our access to natural gas and crude oil markets or delay our production. The availability of a ready market for natural gas and crude oil production depends on a number of factors, including the demand for and supply of natural gas and crude oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for the lack of a market or because of inadequacy, unavailability or the pricing associated with natural gas pipelines, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until we made production arrangements to deliver the product to market. Thus, our profitability would be adversely affected.

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

We use derivatives for a portion of our natural gas and crude oil production from our own wells, our partnerships and for natural gas purchases and sales by our marketing subsidiary to achieve a more predictable cash flow, to reduce exposure to adverse fluctuations in the prices of natural gas and crude oil, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected, the counter-party to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive.

In addition, derivative arrangements may limit the benefit from increases in the prices for natural gas and crude oil. They may also require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently

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qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than if our derivative instruments qualified for hedge accounting. For instance, if natural gas and crude oil prices rise significantly, it could result in significant non-cash charges each quarter, which could have a material negative effect on our net income.

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

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

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. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats 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 position, 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 do not carry contingent business interruption insurance related to the processing plants owned by our natural gas purchasers or oil refineries owned by our crude oil purchasers. For some risks, such as drilling blow-out insurance, we may not obtain insurance if we believe the cost of available insurance is prohibitive relative to the perceived risks presented. 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 and introductions of new products and services using new technologies. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, other natural gas and crude oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

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

Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce natural gas and crude oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas and crude oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas and crude oil market prices. Larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which can adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because many companies in our industry have greater financial and human resources, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and crude oil properties. These factors could adversely affect the success of our operations and our profitability.

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

Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and crude oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other

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damages. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

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

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

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

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

In February 2012, U.S. President Barack Obama ("President Obama") and his administration (the "Obama 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 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 operation.
New derivatives legislation and regulation could adversely affect our ability to hedge natural gas and crude oil prices and increase our costs and adversely affect our profitability.

In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act regulates derivative transactions, including our natural gas and crude oil hedging swaps (swaps are broadly defined to include most of our hedging instruments). The new law required the issuance of new regulations and administrative procedures related to derivatives within one year, but that implementation has been delayed until at least July 2012 and will initially consist of reporting and data gathering requirements, with substantive regulation to follow. The effect of such future regulations on our business is currently uncertain. In particular, note the following:
The Dodd-Frank Act may decrease our ability to enter into hedging transactions which would expose us to additional risks related to commodity price volatility; commodity price decreases would then have an immediate significant adverse affect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.
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.
We expect that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased counterparty costs, thereby increasing the costs of derivative instruments. Our derivatives counterparties may be subject to significant new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act.
The Dodd-Frank Act contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these

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requirements for entities that use swaps to hedge or mitigate commercial risk. While we may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking proceedings.
The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms.

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

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

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

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

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or increased costs for insurance.
    
Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate
that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

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

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

Risks Associated with Our Indebtedness
    
Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could

26



adversely affect our operations. Our lenders can unilaterally reduce our borrowing availability based on anticipated sustained natural gas and crude oil prices.

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

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

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

The indentures governing our outstanding notes and our senior credit facility contain (and we anticipate that the indentures governing any other debt securities we may issue will also contain) various restrictive covenants that limit management’s discretion in operating our business. In particular, these covenants limit our ability to, among other things:
incur additional debt;
make certain investments or pay dividends or distributions on our capital stock, or purchase, redeem or retire capital stock;
sell assets, including capital stock of our restricted subsidiaries;
restrict dividends or other payments by restricted subsidiaries;
create liens;
enter into transactions with affiliates; and
merge or consolidate with another company.

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

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

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

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

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

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


27



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

Risks Associated with Our Joint Venture

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

The board of managers of the joint venture consists of three representatives appointed by us and three representatives appointed by the Investor, each with equal voting power. The joint venture agreement generally requires the affirmative vote of a majority of the members of the board to approve an action, and we and the Investor may not always agree on the best course of action for the joint venture. If such a disagreement were to occur, we would not be able to cause the joint venture to take action that we believed to be in the best interests of the joint venture. Consequently, our best interests may not be advanced and our investment in the joint venture could be adversely affected. If there is a disagreement about a development plan and budget for the joint venture, the Investor is entitled to unilaterally suspend substantially all of the operations of the joint venture, which could have a material adverse impact on the results of operations of the joint venture and our investment. Such a suspension could last for up to two years, at which point either party could elect to dissolve the joint venture or to sell their ownership interests to a third party. The Investor is entitled to a preference with respect to liquidating distributions and proceeds from significant sales of ownership interests up to the amount of its contributed capital, which would diminish our returns if the value of the joint venture had declined at the time of the liquidation or sale.

After a “restricted period” which generally lasts for the four year years following the closing of the joint venture, the Investor can seek to sell its interest in the joint venture to a third party, subject to rights of first offer and refusal in favor of us. If we do not exercise those rights in a sale involving all of the Investor’s ownership interests, the Investor can exercise “drag-along” rights and compel us to sell all of our interests in the proposed transaction. Accordingly, if we possessed insufficient funds and were unable to obtain financing necessary to purchase the Investor’s interest under the rights of first offer and refusal, the Investor might sell its interests in the joint venture to a third party with whom we might have a difficult time in 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES
    
None.



28



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 PETD. 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, 2010
$
25.37

 
$
18.11

April 1 - June 30, 2010
27.73

 
17.92

July 1 - September 30, 2010
30.39

 
23.82

October 1 - December 31, 2010
43.01

 
27.44

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


As of February 17, 2012, we had approximately 790 shareholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our credit facility 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 in this report.


    
The following table presents information about our purchases of our common stock during the three months ended December 31, 2011.

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, 2011
 
175

 
$
26.11

 

 

November 1 - 30, 2011
 
3,755

 
27.52

 

 

December 1 - 31, 2011
 
2,607

 
35.11

 

 

Total fourth quarter purchases
 
6,537

 
30.51

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


29



SHAREHOLDER PERFORMANCE GRAPH

The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2011, 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 235 crude petroleum and natural gas companies. The results shown in the graph below are not necessarily indicative of future performance. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2006, and in the S&P 500 Index and the SIC Index on the same date.

 

30




ITEM 6. SELECTED FINANCIAL DATA


 
Year Ended December 31,

 
2011
 
2010
 
2009
 
2008
 
2007 (3)

 
(in millions, except per share data and as noted)
Statement of Operations
 

 

 

 

 

Natural gas, NGL and crude oil sales
 
$
276.6

 
$
205.0

 
$
171.2

 
$
304.9

 
$
175.2

Commodity price risk management gain (loss), net (1)
 
46.1

 
59.9

 
(10.1
)
 
127.8

 
2.8

Total revenues
 
396.0

 
343.0

 
230.9

 
572.5

 
291.7

Income (loss) from continuing operations
 
3.1

 
6.0

 
(80.1
)
 
105.8

 
26.1


 
 
 

 

 

 

Earnings (loss) per share attributable to shareholders:
 
 
 


 


 


 


Net income (loss) from continuing operations - basic
 
$
0.13

 
$
0.33

 
$
(4.76
)
 
$
7.19

 
$
1.77

Net income (loss) from continuing operations - diluted
 
0.13

 
0.32

 
(4.76
)
 
7.13

 
1.76


 
 
 


 


 


 


Statement of Cash Flows
 
 
 

 

 

 

Net cash provided by operating activities
 
$
166.8

 
$
151.8

 
$
143.9

 
$
139.1

 
$
60.3

Capital expenditures
 
334.5

 
162.7

 
143.0

 
323.2

 
239.0

Acquisitions
 
145.9

 
158.1

 

 

 
255.7


 
 
 

 

 

 

Balance Sheet
 
 
 

 

 

 

Total assets
 
$
1,698.0

 
$
1,389.0

 
$
1,250.3

 
$
1,402.7

 
$
1,050.5

Working capital (deficit)
 
(22.0
)
 
16.2

 
32.9

 
31.3

 
(50.2
)
Long-term debt
 
532.2

 
295.7

 
280.7

 
394.9

 
235.0

Equity
 
664.1

 
642.2

 
538.6

 
512.3

 
396.3


 
 
 

 

 

 

Pricing and Lifting Costs on Continuing Operations
 
 
 

 

 

 

Average sales price (excluding gains/losses on derivatives) (per Mcfe)
 
$
6.15

 
$
5.63

 
$
4.19

 
$
8.37

 
$
6.26

Average sales price (including realized gains/losses on derivatives) (per Mcfe)
 
6.53

 
6.89

 
6.77

 
8.62

 
6.52

Average lifting cost (per Mcfe) (2)
 
0.95

 
1.09

 
0.81

 
1.08

 
0.90

 
 
 
 
 
 
 
 
 
 
 
Production (Bcfe)
 
 
 
 
 
 
 
 
 
 
Production from continuing operations
 
45.0
 
37.0

 
41.6

 
36.9

 
28.0

Production from discontinued operations (3)
 
2.5
 
1.6

 
1.7

 
1.8

 

Total production
 
47.5

 
38.6

 
43.3

 
38.7

 
28.0

 
 
 
 
 
 
 
 
 
 
 
Total proved reserves (Bcfe) (4)
 
1,015.5
 
860.6

 
717.3

 
753.1

 
685.6

______________
(1)
See Note 4, Derivative Financial Instruments, to our consolidated financial statements included in this report.
(2)
Lifting costs represent lease operating expenses, excluding production taxes, on a per unit basis.
(3)
2007 does not present the effects of the divestitures of our Michigan and North Dakota assets as discontinued operations as the amounts related to these operations were immaterial.
(4)
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 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets.

31





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

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

EXECUTIVE SUMMARY

2011 Financial Overview

In 2011, we recorded strong increases in revenues and cash flows from operations. Increased production, liquids to natural gas ratio and crude oil prices were the largest contributors to these increases, despite lower average natural gas prices. Natural gas, NGL and crude oil sales revenue increased 34.9% in 2011 compared to 2010, with increases in production of 21.5% and an overall increase in the average sales price per Mcfe of 9.2%. Leading the increase in production were liquids, with crude oil production increasing 38.9% and NGL production increasing 26.3%, resulting in a liquids to natural gas ratio of 32/68 in 2011 compared to 29/71 in 2010. Our derivative transactions generated revenues of $48.9 million and liquidity of $17.6 million. Available liquidity as of December 31, 2011, was $196.4 million, including $16.6 million related to PDCM for the acquisition and development of Marcellus properties, compared to $379.3 million, which included $23.9 million related to PDCM, as of December 31, 2010. The decrease in available liquidity year-over-year was expected as we intended to use the excess proceeds from our November 2010 capital transactions on the acquisition of natural gas and crude oil properties, specifically our partnership acquisitions and the acceleration of organic growth projects. Available liquidity is comprised of cash, cash equivalents and funds available under our credit facility after giving consideration to our undrawn outstanding letters of credit.

Operational Overview and Update

Drilling Activities. In 2011, we drilled 97 developmental wells and participated in 48 non-operated wells in the Wattenberg Field, of which 123 were completed and turned in line. We also executed 190 refracture and/or recompletion projects in this area. Of the 145 wells drilled, 17 were horizontal Niobrara with 16 of them producing as of December 31, 2011. We drilled 17 developmental wells in the Piceance Basin and PDCM drilled six horizontal Marcellus wells, two of which had been turned in line as of the end of the year, and completed three horizontal Marcellus wells that were in-process as of December 31, 2010. In the Permian Basin, we drilled a total of 23 developmental wells, 15 of which were producing at year end and two of which were determined to be dry holes.

Acquisitions and Leasehold Agreements. In 2011, we entered into leasehold agreements with various unrelated third parties providing us with an option to acquire acreage targeting the wet natural gas and crude oil windows of the Utica Shale play throughout southeastern Ohio. Pursuant to the agreements, we have the right to acquire an estimated 40,000 net acres. Should we exercise our right to acquire all 40,000 acres, we estimate that the purchase price of such leaseholds will approximate $70 million. A portion of the options related to these leaseholds will expire in August 2012. Currently, we are pursuing an industry joint venture partner to participate in and share in funding the growth and development in this play. While we expect to identify a partner by mid-2012, we cannot assure we will be successful in securing a partner or developing this acreage. These Utica Shale acreage expenditures demonstrate our heightened interest in dedicating a portion of our capital budget to exploration, which involves higher risks and the potential for higher rewards. In previous years we have dedicated very little of our expenditures to exploration.
 
In October 2011, PDCM acquired from an unrelated third party 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur"), a West Virginia limited liability company, for the purchase price of $162.9 million, including a post-closing working capital adjustment of $10.4 million. The acquisition included approximately 1,340 gross wells producing 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. Pursuant to our joint venture interest in PDCM, our portion of the purchase price was $81.5 million and we hold a 50% interest in both the wells and acres acquired. We estimate that the acquisition added approximately 8 Bcfe to our total proved reserves as of December 31, 2011. Substantially all of the acreage acquired is held by production and is in close proximity to PDCM's existing properties.

During 2011, we acquired eight affiliated partnerships for an aggregate purchase price of $73 million. These purchases included the non-affiliated investor partners' remaining working interests in a total of 299 gross, 204.2 net, wells located in our Wattenberg Field and Piceance Basin. The acquisition of these partnerships has provided us with immediate growth in both production and proved reserves, and will allow us to realize operational benefits, as well as the opportunity to optimize revenue opportunities by accelerating a refracture and recompletion program of the wells acquired.

Natural Gas and Crude Oil Properties Divestitures. In October 2011, we announced our intent to divest our assets located in the Wolfberry Trend in the Permian Basin in West Texas to focus our efforts in our horizontal drilling programs and to provide partial funding for our 2012 capital budget. During the fourth quarter of 2011, we sold our non-core Permian assets to unrelated third parties for a total of $13.2 million. On December 20, 2011, we executed a purchase and sales 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. The transaction closed on February 28, 2012 with total proceeds received of $184.4 million after preliminary closing adjustments. The proceeds from these sales were used to pay down our corporate credit facility and to provide partial funding for our 2012 capital budget, allowing us to accelerate the development of our liquid-rich inventory of projects in the Wattenberg Field and to fund the acquisition of Utica Shale acreage in Ohio while beginning exploratory activities on this acreage. Our Permian Basin assets were classified as held for sale as of December 31, 2010 and 2011, and the results of operations related to those assets were reported as discontinued operations in 2010, year of acquisition, and 2011, in the

32



accompanying consolidated statements of operations included in this report.

Potential for Future Asset Impairments. The domestic natural gas market remains weak. A further decrease in forward natural gas prices during 2012 could result in significant impairment charges. Our Piceance Basin has significant natural gas reserves, representing 47% of our total proved natural gas reserves and 32% of our total proved reserves, and is sensitive to declines in natural gas prices. These assets, which had a net book value of approximately $308 million at December 31, 2011, are at risk of impairment if future natural gas prices for production in this area experience further long-term decline. 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.
    
Non-U.S. GAAP Financial Measures

We use "adjusted cash flow from operations," "adjusted net income (loss) attributable to shareholders," "adjusted EBITDA" and "PV-10%," non-U.S. GAAP financial measures, for internal managerial purposes, 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, nor 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 nearest U.S. GAAP measure.



33



Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results from continuing operations.
 
Year Ended December 31,
 
 
 
 
 
 
 
Change
 
2011
 
2010
 
2009
 
2011-2010
 
2010-2009
 
(dollars in millions, except per unit data)
 
 
 
 
Production (1)
 
 
 
 
 
 
 
 
 
Natural gas (MMcf) (2)
30,429.7

 
26,239.1

 
34,089.6

 
16.0
 %
 
(23.0
)%
Crude oil (MBbls)
1,709.9

 
1,231.4

 
1,244.0

 
38.9
 %
 
(1.0
)%
NGLs (MBbls) (2)
719.2

 
569.6

 

 
26.3
 %
 
*

Natural gas equivalent (MMcfe) (3)
45,004.8

 
37,044.9

 
41,553.4

 
21.5
 %
 
(10.8
)%
Average MMcfe per day
123.3

 
101.5

 
113.8

 
21.5
 %
 
(10.8
)%
Natural Gas, NGL and Crude Oil Sales
 
 
 
 
 
 
 
 
 
Natural gas (2)
$
99.6

 
$
94.6

 
$
105.4

 
5.3
 %
 
(10.2
)%
Crude oil
149.8

 
91.1

 
68.5

 
64.4
 %
 
33.0
 %
NGLs (2)
27.2

 
22.6

 

 
20.4
 %
 
*

Provision for underpayment of natural gas sales

 
(3.3
)
 
(2.7
)
 
(100.0
)%
 
22.2
 %
Total natural gas, NGL and crude oil sales
$
276.6

 
$
205.0

 
$
171.2

 
34.9
 %
 
19.7
 %
 
 
 
 
 
 
 
 
 
 
Realized Gain (Loss) on Derivatives, net (4)
 
 
 
 
 
 
 
 
 
Natural gas
$
29.1

 
$
40.0

 
$
89.4

 
(27.3
)%
 
(55.3
)%
Crude oil
(11.9
)
 
7.1

 
17.9

 
(267.6
)%
 
(60.3
)%
Total realized gain on derivatives, net
$
17.2

 
$
47.1

 
$
107.3

 
(63.5
)%
 
(56.1
)%
 
 
 
 
 
 
 
 
 
 
Average Sales Price (excluding gain/loss on derivatives)
 
 
 
 
 
 
 
 
 
Natural gas (per Mcf) (2)
$
3.27

 
$
3.61

 
$
3.09

 
(9.4
)%
 
16.8
 %
Crude oil (per Bbl)
87.63

 
73.96

 
55.07

 
18.5
 %
 
34.3
 %
NGLs (per Bbl) (2)
37.82

 
39.66

 

 
(4.6
)%
 
*

Natural gas equivalent (per Mcfe)
6.15

 
5.63

 
4.19

 
9.2
 %
 
34.4
 %
 
 
 
 
 
 
 
 
 
 
Average Sales Price (including realized gain/loss on derivatives)
 
 
 
 
 
 
 
 
 
Natural gas (per Mcf) (2)
$
4.23

 
$
5.13

 
$
5.72

 
(17.5
)%
 
(10.3
)%
Crude oil (per Bbl)
80.69

 
79.70

 
69.44

 
1.2
 %
 
14.8
 %
NGLs (per Bbl) (2)
37.82

 
39.66

 

 
(4.6
)%
 
*

Natural gas equivalent (per Mcfe)
6.53

 
6.89

 
6.77

 
(5.2
)%
 
1.8
 %
 
 
 
 
 
 
 
 
 
 
Average Lifting Cost (per Mcfe) (5)
$
0.95

 
$
1.09

 
$
0.81

 
(12.8
)%
 
34.6
 %
 
 
 
 
 
 
 
 
 
 
Natural Gas Marketing Contribution Margin (6)
$
0.9

 
$
1.1

 
$
2.0

 
(18.2
)%
 
(45.0
)%
 
 
 
 
 
 
 
 
 
 
Other Costs and Expenses
 
 
 
 
 
 
 
 
 
Exploration expense
$
6.3

 
$
13.7

 
$
14.1