10-K 1 d445586d10k.htm FORM 10-K Form 10-K

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

(Mark one)

 

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

For the fiscal year ended December 31, 2012

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 No. 001-32367

 

 

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware   80-0000545
(State or other jurisdiction
of incorporation or organization)
  (IRS Employer Identification No.)

1099 18th Street, Suite 2300

Denver, Colorado

  80202

(Address of principal

executive offices)

  (Zip Code)

(303) 293-9100

(Registrant’s telephone number, including area code)

 

 

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock, $.001 par value   New York Stock Exchange
Series A Junior Participating Preferred Stock Purchase Rights   New York Stock Exchange

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    x  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    x  No

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.    x  Yes    ¨  No

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

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

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

 

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2012 based on the $21.42 closing price of the registrant’s common stock on the New York Stock Exchange was $672,834,394.

 

* Calculated based on beneficial ownership of our common stock on January 25, 2013. Without assuming that any of the registrant’s directors, executive officers, or 10 percent or greater beneficial owners is an affiliate, the shares of which they are beneficial owners have been deemed to be owned by affiliates solely for this calculation.

As of January 25, 2013, the registrant had 48,173,986 outstanding shares of $.001 per share par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE

The information required in Part III of this Annual Report on Form 10-K is incorporated by reference from the registrant’s definitive proxy statement for the registrant’s Annual Meeting of Stockholders to be held in May 2013 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant’s fiscal year ended December 31, 2012.

 

 

 


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements about our future strategy, plans, estimates, beliefs, timing and expected performance.

All of these types of statements, other than statements of historical fact included in or incorporated into this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in “Items 1 and 2. Business and Properties,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other sections of this Annual Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as “expect,” “seek,” “believe” “upside,” “will,” “may,” “expect,” “anticipate,” “plan,” “will be dependent on,” “project,” “potential,” “intend,” “could,” “should,” “estimate,” “predict,” “pursue,” “target,” “objective,” or “continue,” the negative of such terms or other comparable terminology.

Forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the following risks and uncertainties:

 

   

volatility of market prices received for natural gas, natural gas liquids (“NGLs”) and oil;

 

   

actual production;

 

   

changes in the estimates of proved reserves;

 

   

reductions in the borrowing base under our revolving bank credit facility (the “Amended Credit Facility”);

 

   

legislative or regulatory changes that can affect our ability to receive drilling and other permits and surface rights, including initiatives related to drilling and completion techniques including hydraulic fracturing;

 

   

availability of third party goods and services at reasonable rates;

 

   

liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance; and

 

   

other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in Item 1A, “Risk Factors” all of which are difficult to predict.

In light of these and other risks, uncertainties and assumptions, forward-looking events may not occur.

The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to many factors including those listed above and in “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.

 

- 1 -


All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Readers should not place undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not intend to, and do not undertake any obligation to, publicly update or revise any forward-looking statements as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

- 2 -


PART I

 

Items 1 and 2. Business and Properties

BUSINESS

General

Bill Barrett Corporation together with our wholly-owned subsidiaries (“the Company”, “we”, “our” or “us”) develops oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value through profitable growth in cash flow, reserves and production through the development of our oil and natural gas assets. Due to the decline in natural gas and NGL prices, we have shifted our focus to developing our oil resources, where we have established a long-term drilling inventory at our core oil programs. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGLs recovery at market prices and from the settlement of commodity hedges.

We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. Since inception, we have built our portfolio of properties primarily through acquisitions where we seek to add value through our geologic and operational expertise. Our acquisitions have included key assets in the Piceance (Colorado), Uinta (Utah), Denver-Julesburg (Colorado and Wyoming), Powder River (Wyoming) and Wind River (Wyoming) Basins in the Rocky Mountain region (the “Rockies”). We also may sell properties when the opportunity arises or when business conditions warrant, as demonstrated by the sale of our Wind River Basin and Powder River Basin properties and a portion of our Piceance Basin properties in 2012.

We are committed to exploring for, developing and producing oil and natural gas in a responsible and safe manner. We work diligently with environmental, wildlife and community organizations to ensure that our exploration and development activities are designed with all stakeholders in mind.

We operate in one industry segment, which is the exploration, development and production of crude oil and natural gas, and all of our operations are conducted in the United States. Consequently, we currently report a single reportable segment. See “Financial Statements” and the notes to our consolidated financial statements for financial information about this reportable segment. See definitions of oil and natural gas terms below at “— Glossary of Oil and Natural Gas Terms.”

The following table provides information regarding our operations by basin as of December 31, 2012:

 

Basin/Area

   State    Estimated  Net
Proved
Reserves(1)
(Bcfe)
     December 2012
Average Daily
Net Production
(MMcfe/d)
     Net
Producing
Wells(2)
     Net
Undeveloped
Acreage
 

Piceance(3)

   CO      400.8         141.5         744.2         40,098 (4) 

Uinta – West Tavaputs

   UT      264.7         95.3         279.7         19,904 (5) 

Uinta Oil

   UT      281.7         31.5         131.0         66,528 (6) 

Denver-Julesburg

   CO/WY      74.8         10.0         179.7         50,881   

Powder River Oil

   WY      21.2         2.0         14.3         54,579   

Other

   Various      0.5         41.0         11.8         855,600 (7) 
     

 

 

    

 

 

    

 

 

    

 

 

 

Total

        1,043.7         321.3         1,360.7         1,087,590 (8) 
     

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Our proved reserves were determined in accordance with Securities and Exchange Commission, or SEC, guidelines, using the average price on the first of each month for natural gas (CIG price) and oil (WTI price), which averaged $2.56 per MMBtu of natural gas and $91.21 per barrel of oil in 2012, without giving effect to hedging transactions. CIG refers to Colorado Interstate Gas price as quoted in Platt’s Gas Daily on

 

- 3 -


  the first flow day of each month. WTI refers to West Texas Intermediate price as quoted by Plains All American Pipeline, L.P. using crude oil price bulletins for the first day of each month. Our reserves estimates are based on a reserve report prepared by us and audited by our independent third party petroleum engineers. See “—Oil and Gas Data—Proved Reserves.”
(2) Net wells are the sum of our fractional working interests owned in gross wells.
(3) Reflects sale of a partial interest that closed on December 31, 2012 of our Gibson Gulch acreage.
(4) Includes 36,281 net undeveloped acres associated with our Cottonwood Gulch prospect.
(5) Does not include an additional 16,119 net undeveloped acres that are subject to drill-to-earn agreements.
(6) Does not include an additional 54,274 net undeveloped acres that are subject to drill-to-earn agreements.
(7) Does not include an additional 47,797 net undeveloped acres that are subject to drill-to-earn agreements.
(8) Does not include an additional 118,190 net undeveloped acres that are subject to drill-to-earn agreements.

Our Offices

Our principal executive offices are located at 1099 18th Street, Suite 2300, Denver, Colorado 80202, and our telephone number at that address is (303) 293-9100.

Areas of Operation

 

LOGO

Overview

Through our operations, we have transitioned our portfolio to have a better balance in the mix of oil, natural gas, and NGLs for both production and reserves. We had four key development areas as of December 31, 2012, including the Uinta Oil Program in the Uinta Basin, the Denver-Julesburg Basin, the Gibson Gulch area in the Piceance Basin, and the West Tavaputs area in the Uinta Basin. We also hold acreage in the Powder River and other exploration areas. Among our four key development programs, two target oil, one targets natural gas and NGLs, and the fourth is a dry natural gas play.

 

- 4 -


The following are descriptions of our development areas.

Uinta Basin

The Uinta Basin is located in northeastern Utah. Our development operations are conducted through two key programs: our Uinta Oil Program and the West Tavaputs area, which is primarily natural gas development. We also have a position in several exploration prospects in the Uinta Basin.

Uinta Oil Program

Key Statistics

 

   

Estimated proved reserves as of December 31, 2012—281.7 Bcfe (47.0 MMBoe).

 

   

Producing wells—We had interests in 226 gross (131.0 net) producing wells as of December 31, 2012, and we serve as operator in 158 gross wells.

 

   

2012 net production—11.5 Bcfe (1.9 MMBoe).

 

   

Acreage—We held 66,528 net undeveloped acres as of December 31, 2012, along with 54,274 net undeveloped acres that are subject to drill-to-earn agreements.

 

   

Capital expenditures—In 2012, our capital expenditures were $314.5 million to drill 106 gross (70.2 net) wells and acquire leasehold acres.

 

   

As of December 31, 2012, we were in the process of drilling three gross (1.4 net) wells and waiting to complete three gross (1.9 net) wells.

The Uinta Oil Program is a fractured oil play with multiple pay zones that we believe has significant upside. This program currently consists of four main areas of development: Blacktail Ridge, Lake Canyon, East Bluebell and South Altamont. As part of our strategy to increase the oil share of our production mix, we increased our net acreage position by 23,685 net acres to 100,428 net acres during 2012. We have 1,696 potential drilling locations and 281.7 Bcfe of estimated proved reserves and a weighted average working interest of 54% in the Uinta Oil Program.

As of December 31, 2012, our focus is in developing the Green River and Wasatch formations. For the 2013 Green River-Wasatch development program, we are continuing to vertically drill interior field locations as well as testing the western productivity extent of the field on 160 acre density. In addition to the 160 acre density development of the Green River-Wasatch vertical program, we are currently drilling and evaluating 80 acre density pilot areas on two 640 acre sections within Blacktail Ridge. Plans are for a four rig drilling program in the Uinta Oil Program in 2013, which may be adjusted throughout the year as business conditions and operating results warrant.

In 2013, we plan to drill and complete 84 gross operated wells and expect to participate in eight gross (1.9 net) non-operated wells in the Uinta Oil Program.

Our four areas of development within the Uinta Oil Program have varying working interests. At December 31, 2012, in the Blacktail Ridge area, we had 11,923 net undeveloped acres with an additional 15,748 net undeveloped acres subject to drill-to-earn agreements. Under our exploration and development agreement with the Ute Indian Tribe of the Uintah and Ouray Reservation (“Ute Tribe”) and Ute Development Corporation, we serve as operator and have the right to earn a minimum of a 50% working interest in all formations. To earn these interests, we are required to drill a minimum of eight wells per year in the Wasatch formation. The Ute Tribe assigned its participation rights pursuant to the exploration and development agreement to Ute Energy Corporation (“Ute Energy”).

 

- 5 -


At December 31, 2012, in the Lake Canyon area we had 19,573 net undeveloped acres with an additional 39,518 net undeveloped acres subject to drill-to-earn agreements. Under the amended exploration and development agreement with the Ute Tribe and Ute Development Corporation, we operate the northern block of Lake Canyon (consisting of 19,781 net tribal acres) with a 75% working interest, and our industry partner operates the southern block where we retain a 25% working interest. This agreement also requires us and our industry partner to drill at least two wells per year from 2012 through 2015 and an additional 14 wells at some point between 2012 and 2015. The East Bluebell position was acquired in 2011 and, as of December 31, 2012, included 14,263 net undeveloped acres with a mixture of fee, state, federal and tribal minerals, as well as associated gathering and transportation infrastructure.

The South Altamont position was acquired in early 2012 and, as of December 31, 2012, included 20,125 net undeveloped acres of primarily fee acreage and included producing properties.

West Tavaputs Area

Key Statistics

 

   

Estimated proved reserves as of December 31, 2012—264.7 Bcfe.

 

   

Producing wells—We had interests in 298 gross (258 net) producing wells as of December 31, 2012, and we serve as the operator in all of these wells.

 

   

2012 net production—34.9 Bcfe.

 

   

Acreage—We held 19,904 net undeveloped acres as of December 31, 2012, along with 16,119 net undeveloped acres that are subject to drill-to-earn agreements.

 

   

Capital expenditures—In 2012, our capital expenditures were $106.5 million to drill 16 gross wells and install compression and gathering facilities.

 

   

As of December 31, 2012, we were not in the process of drilling or completing any wells.

As of December 31, 2012, we had identified 588 potential drilling locations and 264.7 Bcfe of estimated proved reserves in the West Tavaputs area with a weighted average working interest of 76%. We are targeting the gas-productive sands of the Wasatch and Mesaverde formations at average depths of 7,600 feet on average. We drilled 16 wells and completed 32 wells in 2012. We do not plan to drill any wells in the West Tavaputs area in 2013.

Our natural gas production in the West Tavaputs area is currently gathered through our own gathering systems and is delivered into Questar Pipeline Company and Three Rivers Gathering, LLC. Gas delivered into Questar Pipeline is processed by Questar Transportation Services Company, and gas delivered into Three Rivers Gathering is processed by QEP Field Services Co and Chipeta Processing LLC. Gas is then be marketed through a variety of pipelines including Questar Pipeline Company, Northwest Pipeline, CIG, Ruby Pipeline LLC, Rockies Express Pipeline LLC, and Wyoming Interstate Gas Company Pipeline. In November 2012, a breach and fire occurred on one of our gathering pipelines adjacent to our Dry Canyon compressor station, injuring two employees. The fire spread to the compressor station damaging the 10 compressors on location as well as other equipment. As a result, for approximately three weeks we were not able to transport a portion of our West Tavaputs gas production. Production in 2012 was reduced by approximately 1.2 Bcfe. In December 2012, a bypass pipeline was completed, allowing us to produce and transport approximately 78 MMcfe per day, or 90% of our pre-fire volumes. Pipeline repairs to direct additional production to our Sage Brush compressor station will be completed in the first quarter of 2013, modestly increasing production. We have begun repairs on the compressors and related equipment and expect to be able to complete all repairs and restore full capacity in the third quarter of 2013. Our uninsured costs are not expected to be material.

 

- 6 -


Denver-Julesburg Basin

The Denver–Julesburg Basin (“DJ Basin”) is located in Colorado’s eastern plains and parts of southern Wyoming, western Kansas and western Nebraska. We entered this area through our initial acquisition of oil and gas properties in August 2011 and have since continued acreage acquisitions and leasing activities.

Key Statistics

 

   

Estimated proved reserves as of December 31, 2012—74.8 Bcfe (12.5 MMBoe).

 

   

Producing wells—We had interests in 259 gross (179.7 net) producing wells as of December 31, 2012, and we serve as operator in 180 gross wells.

 

   

2012 net production—3.6 Bcfe (0.6 MMBoe).

 

   

Acreage—We held 50,881 net undeveloped acres as of December 31, 2012.

 

   

Capital expenditures—Our capital expenditures for 2012 were $124.9 million for participation in the drilling of eight gross wells and to acquire leasehold acres.

 

   

As of December 31, 2012, we were not in the process of drilling any wells, and we were waiting to complete two gross (1.5 net) wells within the DJ Basin.

Development activity in the DJ Basin utilizes horizontal drilling technology to target the Niobrara formations. As of December 31, 2012, we had identified 1,082 potential drilling locations and 74.8 Bcfe of estimated proved reserves in the DJ Basin with a weighted average working interest of 74%. Our gas production is gathered and processed by third parties, and our oil production is sold at the lease location and trucked to markets.

Our 2013 drilling program anticipates running two rigs to drill and complete approximately 65 gross operated wells and participate in approximately 20 gross (5.0 net) non-operated wells, which may be adjusted throughout 2013 as business conditions and operating results warrant.

Piceance Basin

The Piceance Basin is located in northwestern Colorado. We began operations in the Gibson Gulch area of the Piceance Basin on September 1, 2004, after we purchased producing and undeveloped properties.

Key Statistics

 

   

Estimated proved reserves as of December 31, 2012—400.8 Bcfe.

 

   

Producing wells—We had interests in 955 gross (744.2 net) producing wells as of December 31, 2012, and we serve as the operator in 925 gross wells.

 

   

2012 net production—51.8 Bcfe.

 

   

Acreage—We held 40,098 net undeveloped acres, including the Cottonwood Gulch prospect, as of December 31, 2012.

 

   

Capital expenditures—Our capital expenditures for 2012 were $207.7 million for participation in the drilling of 91 gross wells and to expand our compression and gathering facilities in the Piceance Basin.

 

   

As of December 31, 2012, we were not in the process of drilling or completing any wells.

The Gibson Gulch area is a basin-centered gas play along the north end of the Divide Creek anticline near the eastern limits of the Piceance Basin’s productive Mesaverde (Williams Fork) trend, and is at a depth of approximately 7,500 feet. Through 2006, we drilled on a 20-acre well density. Reserves in this area are based on 10-acre density. On December 31, 2012, we closed the sale of an 18% working interest in our Gibson Gulch properties; the working interest sold progresses to 26% in 2016.

 

- 7 -


Our natural gas production in this basin is currently gathered through our own gathering system and Summit Midstream Partner, LLC’s gathering system and delivered to markets through a variety of pipelines, including pipelines owned by Questar Pipeline Company, Northwest Pipeline, Colorado Interstate Gas, TransColorado Pipeline, Wyoming Interstate Gas Company Pipeline and Rockies Express Pipeline LLC. The energy content of our Piceance gas is approximately 1.15 BTU per cubic foot, and the natural gas is processed at an Enterprise Products Partners L.P. plant in Meeker, Colorado. We have the option annually to elect to process liquids with Enterprise Products Partners L.P. and receive the value of NGLs for a portion of our production. Prior to 2013, we elected to exercise that option and received Oil Price Information Service (“OPIS”) Mt. Belvieu prices for our NGLs, which are currently priced at a premium to natural gas on an energy equivalent basis. Effective January 1, 2013, we modified our gas processing agreement with the processor of a portion of our natural gas in the Gibson Gulch area to take title to NGLs processed under the agreement. As a result, we plan to record those NGLs in our reserves and to separately report production of NGLs beginning in 2013.

We currently do not plan to drill in the Piceance Basin in 2013. This plan may change during the year as business conditions and operating results warrant.

Powder River Basin

The Powder River Basin is located in northeastern Wyoming. Our current operations in the Powder River Basin target oil reservoirs. On December 31, 2012, we sold our coalbed methane producing properties in the Powder River Basin.

Powder River Oil

Our Powder River Oil Program consists of horizontal wells targeting various Cretaceaous oil bearing horizons including the Parkman, Sussex, Shannon, Niobrara, Turner and Frontier formations.

Key Statistics

 

   

Estimated reserves as of December 31, 2012—21.2 Bcfe (3.5 MMBoe).

 

   

Producing wells—We had interests in 74 gross (14.3 net) producing wells as of December 31, 2012, and we serve as operator in 11 gross wells.

 

   

2012 net production—0.7 Bcfe (0.1 MMBoe).

 

   

Acreage—We held 54,579 net undeveloped acres as of December 31, 2012.

 

   

Capital expenditures—Our capital expenditures for 2012 were $47.4 million for participation in the drilling of 20 gross (5.3 net) wells and to acquire leasehold acres.

 

   

As of December 31, 2012, we were in the process of drilling one gross (0.7 net) wells and waiting to complete two gross (0.4 net) wells in the Powder River Oil.

In 2013, we plan to drill and complete at least five gross operated wells and expect to participate in approximately three gross non-operated wells.

Oil and Gas Data

Historically, we have presented separate reserve data for oil and natural gas. This is known as “two streams” reporting and is the manner in which the data below is presented. Beginning January 1, 2013, we modified our gas processing agreements with various processors to take title to NGLs resulting from the processing of our natural gas. We intend to report reserve and production data for oil, natural gas and NGLs for periods after January 1, 2013. This is known as “three streams reporting”.

 

- 8 -


Proved Reserves

The following table presents our estimated net proved oil and natural gas reserves and the present value of our estimated proved reserves at each of December 31, 2012, 2011 and 2010 based on reserve reports prepared by us and audited in their entirety by outside independent third party petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our estimates independently audited, we are required by our revolving credit agreement with our lenders to have an independent third party engineering firm perform an annual audit of our estimated reserves. All of our proved reserves included in our reserve reports are located in North America. Netherland, Sewell & Associates, Inc., or “NSAI”, audited all of our reserves estimates at December 31, 2012, 2011 and 2010. NSAI is retained by and reports to the Reserves Committee of our Board of Directors, which is comprised of independent directors. When compared on a well-by-well or lease-by-lease basis, some of our internal estimates of net proved reserves are greater and some are less than the estimates of outside independent third party petroleum engineers. However, in the aggregate, the independent third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates. In addition to a third party audit, our reserves are reviewed by our Reserves Committee. The Reserves Committee reviews the final reserves estimates in conjunction with NSAI’s audit letter and meets with the key representative of NSAI to discuss NSAI’s review process and findings. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency, other than the SEC, since January 1, 2012.

 

     As of December 31,  

Proved Reserves:

   2012      2011      2010  

Proved Developed Reserves:

        

Natural gas (Bcf)

     492.1         632.5         499.4   

Oil (MMBbls)

     20.7         10.4         6.0   

Total proved developed reserves (Bcfe)

     616.3         694.9         535.2   

Proved Undeveloped Reserves:

        

Natural gas (Bcf)

     247.1         548.6         540.9   

Oil (MMBbls)

     30.1         20.2         7.0   
  

 

 

    

 

 

    

 

 

 

Total proved undeveloped reserves (Bcfe)(1)

     427.4         669.7         583.2   
  

 

 

    

 

 

    

 

 

 

Total Proved Reserves (Bcfe)(1)

     1,043.7         1,364.7         1,118.3   
  

 

 

    

 

 

    

 

 

 

 

(1) Total does not add because of rounding.

The data in the above table represent estimates only. Oil and natural gas reserve engineering is an estimation of accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil and natural gas that are ultimately recovered. See “Item 1A. Risk Factors.”

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those locations on development spacing areas that are offsetting economic producers that are reasonably certain of economic production when drilled. Proved undeveloped reserves for other undrilled development spacing areas can be claimed only where it can be demonstrated with reasonable certainty that there is continuity of economic production from the existing productive formation. Proved undeveloped reserves are included when they are scheduled to be drilled within five years.

 

- 9 -


The following tables illustrate the history of our proved undeveloped reserves from December 31, 2010 through December 31, 2012:

 

     As of December 31,  

Proved Undeveloped Reserves:

   2012     2011     2010  

Beginning Balance (Bcfe)

     669.7        583.2        484.6   

Additions from drilling program

     106.7        118.0        127.0   

Acquisitions

     —          71.5        —     

Engineering/Price revisions

     (91.2     58.1        75.7   

Converted to proved developed

     (136.8     (156.3     (99.9

Sold/Expired/Other

     (121.0     (4.8     (4.2
  

 

 

   

 

 

   

 

 

 

Total Proved Reserves (Bcfe) (1)

     427.4        669.7        583.2   
  

 

 

   

 

 

   

 

 

 

 

     Year ended December 31,  
     2012     2011     2010  

Proved undeveloped wells converted to proved developed during year

     179        182        130   

Proved undeveloped drilling and completion capital invested (in millions)

   $ 362.2      $ 209.9      $ 160.2   

Proved undeveloped facilities capital invested (in millions)

   $ 45.6      $ 20.0      $ 28.1   

Percentage of proved undeveloped converted to proved developed

     20.4     22.7     17.2

Prior year’s proved undeveloped reserves remaining undeveloped at current year end (Bcfe)

     323.8        422.0        380.5   

At December 31, 2012, our proved undeveloped reserves were 427.4 Bcfe. At December 31, 2011, our proved undeveloped reserves were 669.7 Bcfe. During 2012, 113.4 Bcfe, or 17.0% of our December 31, 2011 proved undeveloped reserves (179 wells), were converted into proved developed reserves and required $362.2 million of drilling and completion capital and $45.6 million of facilities capital. These wells produced 23.4 Bcfe in 2012. During 2012, we added 106.7 Bcfe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. During 2012, 121.0 Bcfe were removed from the proved undeveloped reserves category because they were not included in our near term development plans and were either traded, sold or removed. This volume includes 71.4 Bcfe of proved undeveloped reserves sold in the above mentioned divestiture of our Wind River Basin and Powder River Basin (coalbed methane) properties and a portion of our Piceance Basin properties. Negative engineering and pricing revisions reduced proved undeveloped reserves by 91.2 Bcfe. Significant pricing revisions occurred in many of our producing areas, particularly our West Tavaputs “dry” natural gas producing field, due to the pricing change from $3.93 per MMBtu CIG for the year ended December 31, 2011 to $2.56 per MMBtu CIG for the year ended December 31, 2012 and from $92.71 per Bbl WTI for the year ended December 31, 2011 to $91.21 per Bbl WTI for the year ended December 31, 2012. Included in this amount were downward price and performance revisions of 126.8 Bcfe at the West Tavaputs natural gas field. Beginning in 2012, production performance from our 2009 to 2011 20-acre infill drilling program in this “tight gas” Mesa Verde/Wasatch formation has lagged behind pre-drilling estimates of the infill well performance, as we now interpret more interference with the original, 40-acre-spaced, wellbores. A geological and engineering review of the field’s performance has resulted in all remaining proved undeveloped drilling locations, as well as all proved developed producing well estimates to be revised downward to match performance to date. Various other oil and gas fields had a combined negative performance revision of 5.3 Bcfe. Offsetting these, a positive engineering revision in Uinta Oil Program included 40.9 Bcfe increase in proved undeveloped reserves, resulting from increased operational focus and engineering and geological study. The proved undeveloped reserves from December 31, 2011 that remain in the proved undeveloped reserves category at December 31, 2012 are 323.8 Bcfe.

At December 31, 2011, our proved undeveloped reserves were 669.7 Bcfe. At December 31, 2010, our proved undeveloped reserves were 583.2 Bcfe. During 2011, 132.4 Bcfe, or 22.7% of our December 31, 2010 proved undeveloped reserves (182 wells), were converted into proved developed reserves and required $209.9

 

- 10 -


million of drilling and completion capital and $20 million of facilities capital. These wells produced 24.0 Bcfe in 2011. An additional 4.8 Bcfe were removed from the proved undeveloped reserves category because they were either traded, sold or removed because they were not included in our near term development plans. Positive engineering and pricing revisions added 58.1 Bcfe to the proved undeveloped reserves category. The positive engineering revision in the proved undeveloped reserve category in the Gibson Gulch area of the Piceance Basin included 11.0 Bcfe resulting from the addition of proved undeveloped reserves in locations greater than one spacing unit from economic producers. Production from the Gibson Gulch area is from a very large, basin-centered gas accumulation containing reservoirs with no apparent downdip water. The reasonable certainty for economic reserves from these locations is supported by geologic, engineering and economic data in addition to well productivity across the Gibson Gulch area and across the Piceance Basin. The positive engineering revision in the Blacktail Ridge area of the Uinta Basin included 47.9 Bcfe resulting from increased operational focus and engineering and geological study. Small pricing revisions occurred in many of our producing areas due to the pricing change from $3.95 per MMBtu CIG for the year ended December 31, 2010 to $3.93 per MMBtu CIG for the year ended December 31, 2011 and from $75.96 per Bbl WTI for the year ended December 31, 2010 to $92.71 per Bbl WTI for the year ended December 31, 2011. The proved undeveloped reserves from December 31, 2010 that remain in the proved undeveloped reserves category at December 31, 2011 are 422.0 Bcfe. The December 31, 2011 proved undeveloped reserves of 669.7 Bcfe is calculated by adding (i) the December 31, 2010 proved undeveloped reserves of 583.2 Bcfe, plus (ii) the proved undeveloped reserves generated in 2011 from the 2010 and 2011 drilling programs (118.0 Bcfe) and acquisitions (71.5 Bcfe), plus (iii) the sum of the engineering and pricing revisions (58.1 Bcfe), minus (a) the proved undeveloped reserves that were either traded, sold, exceeded the five year limit or not included in our near term development plan (4.8 Bcfe) and (b) the proved undeveloped reserves converted to proved developed reserves (156.3 Bcfe, which includes their production of 24.0 Bcfe). The 118.0 Bcfe of new proved undeveloped reserves generated in 2011 were the result of estimating reserves with reasonable certainty of economic production when drilled on undrilled acreage in development spacing areas that were directly offsetting new economic producers.

The majority of production from the Gibson Gulch area of the Piceance Basin is from the discontinuous fluvial sands of the Williams Fork formation. The resource is consistent across the Gibson Gulch area and results in low variability of estimated ultimate recoveries. The 2011 results of proved undeveloped drilled wells in offsets that are two and three spacing areas from economic producing wells were positive and supported a fourth offset in the proved undeveloped reserve category internal to the producing area of the field as of December 31, 2011 (four wells, 2.4 Bcfe). New technologies were not used to support these reserves. The opportunity to use this data to prove more than one direct offset from economic producers is the result of a change in definition of undeveloped oil and gas reserves included in the SEC’s “Modernization of Oil and Gas Reporting” and applied in our December 31, 2009, 2010 and 2011 reserve reports. The proved undeveloped reserves added in the Gibson Gulch area at December 31, 2011 were 19.5 Bcfe, of which 11.0 Bcfe were attributed to the addition of proved undeveloped reserves in locations greater than one spacing unit from economic producers. Acquisitions added 2.3 Bcfe of the 19.5 Bcfe proved undeveloped reserve addition in Gibson Gulch.

In 2010, the results of the proved undeveloped drilled wells in Gibson Gulch in offsets that are two spacing areas from economic producing wells were positive and supported a third offset in the proved undeveloped reserve category as of December 31, 2010 (39 wells, 24.7 Bcfe). New technologies were not used to support these reserves. The proved undeveloped reserves added in the Gibson Gulch area at December 31, 2010 were 124.7 Bcfe, of which 24.7 Bcfe were attributed to the addition of an offset that is three spacing areas from economic producers.

At December 31, 2012, we also revised our total proved reserves downward by 127.2 Bcfe due to the combined effects of year end 2012 pricing and the 20-acre infill drilling performance at the West Tavaputs area, described above.

At December 31, 2011, we also revised our proved reserves upward by 37.9 Bcfe, excluding pricing revisions, due primarily to the positive results of increased operational focus and engineering and geological

 

- 11 -


study of our Blacktail Ridge property. Blacktail Ridge became a focus for us in 2011 following positive results from our 2010 drilling program. An additional positive revision of 5.5 Bcfe occurred due to the positive change in oil pricing described above.

We use our internal reserves estimates rather than the estimates from independent third party engineering firms because we believe that our reserve and operations engineers are more knowledgeable about the wells due to our continual analysis throughout the year as compared to the relatively short term analysis performed by the independent third party engineers. We use our internal reserves estimates on all properties regardless of the positive or negative variance to the independent third party engineers. If a variance greater than 10% occurs at the field level, it may suggest that a difference in methodology or evaluation techniques exists between us and the independent third party engineers. These differences are investigated by us and the independent third party engineers and discussed with the independent third party engineers to confirm that we used the proper methodologies and techniques in estimating reserves for these fields. These variances also are reviewed with our Reserves Committee of our Board of Directors. These differences are not resolved to a specified tolerance at the field or property level. In the aggregate, the independent third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates.

The internal review process of our wells and the related reserves estimates, and the related internal controls we utilize, includes but is not limited to the following:

 

   

A comparison is made and documented of actual and historical data from our production system to the data in the reserve database. This ensures the accuracy of the production data, which supplies the basis for forecasting.

 

   

A comparison is made and documented of land and lease record to interest data in the reserve database. This ensures that the costs and revenues will be properly determined in the reserves estimation.

 

   

A comparison is made of the historical costs (capital and expenses) to the capital and lease operating costs in the reserve database. Documentation lists reasons for deviation from direct use of historical data. This ensures that all costs are properly included in the reserve database.

 

   

A comparison is made of input data to data in the reserve database of all property acquisitions, disposals, retirements or transfers to verify that all are accounted for accurately.

 

   

Natural gas pricing for the first flow day of every month is collected from Platts Gas Daily and oil pricing is collected from Plains All American Pipeline, L.P. At the end of the year, the 12-month average prices are determined. A similar collection process occurs with pricing deductions supplied by our internal marketing group, and a 12-month average is calculated at year end. A comparison is made of our determination of SEC pricing requirements to that supplied by the third party independent engineering firm. This provides verification of the pricing calculations.

 

   

A final check is made of all economic data inputs in the reserve database by comparing them to documentation provided by our internal marketing, land, accounting, production and operations groups. This provides a second check to ensure accuracy of input data in the reserve database.

 

   

Accurate classification of reserves is verified by comparing independent classification analyses by our internal reservoir engineers and the third party independent engineers. Discrepancies are discussed and differences are jointly resolved.

 

   

Internal reserves estimates are reviewed by well and by area by the Manager – Reserves. A variance by well to the previous year-end reserve report is used as a tool in this process. This review is independent of the reserves estimation process.

 

   

Reserves variances are discussed among the internal reservoir engineers and the Manager – Reserves. Our internal reserves estimates are reviewed by senior management and, beginning with the year-end 2011 reserves, the Reserves Committee of the Board prior to publication.

 

- 12 -


Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is Steven A. Kranker. Mr. Kranker is our Manager – Reserves and has been responsible for our reserves estimates since 2012. Mr. Kranker earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1984. Mr. Kranker has over 28 years’ experience in reserves and economic evaluations, as well as a broad experience in developmental petroleum engineering.

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the technical person primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein is Dan Paul Smith. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. He is a Registered Professional Engineer in the State of Texas (License No. 49093) and has over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering.

NSAI performed a well-by-well audit of all of our properties and of our estimates of proved reserves and then provided us with its audit report concerning our estimates. The audit completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be the same or different from audit procedures performed by other independent third party engineering firms for other oil and gas companies. NSAI’s audit report does not state the degree of its concurrence with the accuracy of our estimate for the proved reserves attributable to our interest in any specific basin, property or well.

The NSAI audit process of our wells and reserves estimates is intended to determine the percentage difference, in the aggregate, of our internal net proved reserves estimate and future net revenue (discounted 10%) and the reserves estimate and net revenue as determined by NSAI. The audit process includes the following:

 

   

The NSAI engineer performs an independent decline curve analysis on proved producing wells based on production and pressure data. This data is provided to NSAI by us as well as other companies operating in the Powder River Basin with respect to the audit of our coalbed methane reserves at December 31, 2010 and 2011.

 

   

The NSAI engineer may verify the production data with the public data.

 

   

The NSAI engineer uses his or her individual interpretation of the information and knowledge of the reservoir and area to make an independent analysis of proved producing reserves.

 

   

The NSAI technical staff will prepare independent maps and volumetric analyses on our properties and offsetting properties. They review our geologic maps, log data, core data, pertinent pressure data, test information and pertinent technical analyses, as well as data from offsetting producers.

 

   

For the reserves estimates of proved non-producing and proved undeveloped locations, the NSAI engineer will estimate the potential for depletion by generating a potentiometric surface map, which relates directly to remaining gas-in-place, and analyzing this information with the maps generated earlier in the process.

 

   

The NSAI engineer will estimate the hydrocarbon recovery of the remaining gas-in-place based upon his/her knowledge and experience.

 

   

The NSAI engineer does not verify our working and net revenue interests or product price deductions.

 

   

The NSAI engineer does not verify our capital costs although he/she may ask for confirming information.

 

   

The NSAI engineer reviews 12 months of operating cost, revenue and pricing information that we provide.

 

- 13 -


   

The NSAI engineer confirms the oil and gas prices used for the SEC reserves estimate.

 

   

NSAI confirms that its reserves estimate is within a 10% variance of our internal net reserves estimate and estimated future net revenue (discounted 10%), in the aggregate, before an audit letter is issued.

 

   

The audit by NSAI is not performed such that differences in reserves or revenue on a well level are resolved to any specific tolerance.

The reserves audit letter provided by NSAI states that “in our opinion the estimates of Bill Barrett’s proved reserves and future revenue shown herein are, in the aggregate, reasonable” following an independent estimation of reserve quantities with economic parameters and other factual data provided by us and accepted by NSAI. The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements (“FASB”), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage NSAI to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its respective employees have no interest in those properties, and the compensation for these engagements is not contingent on NSAI’s estimates of reserves and future cash inflows for the subject properties. During 2012 and 2011, we paid NSAI approximately $446,000 and $318,000, respectively, for auditing our reserves estimates.

 

- 14 -


Production and Price History

The following table sets forth information regarding net production of oil and natural gas and certain price and cost information for each of the periods indicated:

 

     Year Ended December 31,  
   2012      2011      2010  

Production Data:

        

Natural gas (MMcf)

     101,486         97,856         89,964   

Oil (MBbls)

     2,687         1,490         1,089   

Combined volumes (MMcfe)

     117,608         106,796         96,498   

Daily combined volumes (MMcfe/d)

     321.3         292.6         264.4   

Piceance – Gibson Gulch Production Data(1):

        

Natural gas (MMcf)

     48,072         45,606         44,736   

Oil (MBbls)

     619         540         563   

Combined volumes (MMcfe)

     51,786         48,846         48,114   

Daily combined volumes (MMcfe/d)

     141.5         133.8         131.8   

Uinta – West Tavaputs Production Data(1):

        

Natural gas (MMcf)

     34,497         31,719         24,021   

Oil (MBbls)

     61         54         34   

Combined volumes (MMcfe)

     34,863         32,043         24,225   

Daily combined volumes (MMcfe/d)

     95.3         87.8         66.4   

Uinta – Oil Program Production Data:

        

Natural gas (MMcf)

     2,653         1,575         877   

Oil (MBbls)

     1,479         779         438   

Combined volumes (MMcfe)

     11,527         6,249         3,505   

Daily combined volumes (MMcfe/d)

     31.5         17.1         9.6   

DJ Basin – Production Data:

        

Natural gas (MMcf)

     1,264         270         0   

Oil (MBbls)

     397         47         0   

Combined volumes (MMcfe)

     3,646         552         0   

Daily combined volumes (MMcfe/d)

     10.0         1.5         0.0   

Average Costs ($ per Mcfe):

        

Lease operating expense

   $ 0.62       $ 0.53       $ 0.54   

Gathering, transportation and processing expense

     0.91         0.87         0.72   
  

 

 

    

 

 

    

 

 

 

Total production costs excluding production taxes

   $ 1.53       $ 1.40       $ 1.26   

Production tax expense

     0.22         0.35         0.34   

Depreciation, depletion and amortization(2)

     2.91         2.70         2.70   

General and administrative(3)

     0.44         0.45         0.42   

 

(1) The Gibson Gulch area in the Piceance Basin and West Tavaputs area in the Uinta Basin were the only development areas that contained 15% or more of our total proved reserves as of December 31, 2012.
(2) The depreciation, depletion and amortization (“DD&A”) per Mcfe as calculated based on the DD&A expense and MMcfe production data presented in the table for the year ended December 31, 2012 is $2.78. However, the DD&A rate per Mcfe for the year ended December 31, 2012 of $2.91, as presented in the table above, excludes production of 5,465 MMcfe associated with our properties that were sold as of December 31, 2012.
(3)

General and administrative expense presented herein excludes non-cash stock-based compensation of $16.4 million, $19.0 million and $16.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. If included, these non-cash stock based compensation expenses would have increased general and administrative expense by $0.14, $0.18 and $0.18 per Mcfe for the years ended December 31, 2012, 2011 and 2010, respectively. General and administrative expense excluding non-cash stock-based compensation is a non-GAAP measure. Non-cash stock-based compensation is combined with general and

 

- 15 -


  administrative expense for a total of $68.7 million, $66.8 million and $57.8 million for the years ended December 31, 2012, 2011 and 2010, respectively, in the Consolidated Statements of Operations. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expense. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower non-cash stock-based compensation expense.

Productive Wells

The following table sets forth information at December 31, 2012 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

 

     Gas      Oil  
     Gross
Wells
     Net
Wells
     Gross
Wells
     Net
Wells
 

Basin

           

Piceance

     955.0         744.2         0.0         0.0   

Uinta – West Tavaputs

     298.0         279.7         0.0         0.0   

Uinta Oil

     6.0         1.1         220.0         129.8   

DJ

     188.0         135.2         71.0         44.5   

Powder River Oil

     3.0         0.8         71.0         13.5   

Other

     9.0         6.9         10.0         4.9   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     1,459.0         1,167.9         372.0         192.7   
  

 

 

    

 

 

    

 

 

    

 

 

 

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2012 relating to our leasehold acreage.

 

     Developed Acreage(1)      Undeveloped Acreage(2)  
      Gross      Net      Gross      Net  

Basin/Area

           

Piceance(3)

     11,866         8,638         46,171         40,098 (4) 

Uinta – West Tavaputs

     17,414         16,689         23,273         19,904 (5) 

Uinta Oil

     50,707         33,900         163,642         66,528 (6) 

DJ

     32,635         25,405         93,496         50,881   

Powder River Oil

     33,461         12,287         122,489         54,579   

Other

     15,226         13,132         1,210,244         855,600 (7) 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     161,309         110,051         1,659,315         1,087,590 (8) 
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
(3) Reflects sale of a partial interest of our Gibson Gulch acreage that closed on December 31, 2012.
(4) Includes 40,312 gross and 36,281 net acreage associated with the Cottonwood Gulch property.
(5) Does not include an additional 29,307 gross and 16,119 net undeveloped acres that are subject to drill-to-earn agreements.
(6) Does not include an additional 131,596 gross and 54,274 net undeveloped acres that are subject to drill-to-earn agreements.

 

- 16 -


(7) Does not include an additional 123,832 gross and 47,797 net undeveloped acres that are subject to drill-to-earn agreements.
(8) Does not include an additional 284,735 gross and 118,190 net undeveloped acres that are subject to drill-to-earn agreements.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We generally have been able to obtain extensions of the primary terms of our federal leases for the period in which we have been unable to obtain drilling permits due to environmental stipulations, pending environmental analysis or related legal challenge. The following table sets forth, as of December 31, 2012, the expiration periods of the gross and net acres that are subject to leases summarized in the above table of undeveloped acreage.

 

     Undeveloped Acres
Expiring
 

Years Ending:

   Gross      Net  

December 31, 2013

     234,277         146,405   

December 31, 2014

     253,425         123,118   

December 31, 2015

     216,795         148,362   

December 31, 2016

     173,921         126,268   

December 31, 2017 and later

     780,897         543,437 (1) 
  

 

 

    

 

 

 

Total

     1,659,315         1,087,590   
  

 

 

    

 

 

 

 

(1) Includes 263,618 gross and 156,829 net undeveloped acres held by production from other leasehold acreage or held by federal units.

Drilling Results

The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found or economic value. Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

 

     Year Ended
December 31,
2012
     Year Ended
December 31,
2011
     Year Ended
December 31,
2010
 
     Gross      Net      Gross      Net      Gross      Net  

Development

                 

Productive

     324.0         218.7         279.0         191.4         241.0         221.1   

Dry

     0.0         0.0         0.0         0.0         0.0         0.0   

Exploratory

                 

Productive

     3.0         1.5         6.0         3.3         4.0         3.1   

Dry

     3.0         2.7         3.0         1.4         8.0         6.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

                 

Productive

     327.0         220.2         285.0         194.7         245.0         224.2   

Dry

     3.0         2.7         3.0         1.4         8.0         6.1   

 

- 17 -


Operations

General

In general, we serve as operator of wells in which we have a greater than 50% working interest. In addition, we seek to be operator of wells in which we have lesser interests. As operator, we obtain regulatory authorizations, design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or the majority of the other oil field service equipment used for drilling or maintaining wells on the properties we operate. We do construct, operate and maintain a majority of the gas gathering facilities associated with our gas fields. Independent contractors engaged by us provide the majority of the equipment and personnel associated with these activities. We entered into a sale-leaseback transaction in 2012 with respect to the majority of our compression facilities. We lease these facilities from the financial institutions that purchased them and operate these facilities on their behalf. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Financing Activities—Lease Financing Obligation Due 2020”. We employ drilling, production and reservoir engineers and geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Marketing and Customers

We market the majority of the oil and natural gas production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our production to a variety of purchasers under contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. Purchasers include pipelines, processors, marketing companies, local distribution companies and end users. We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations.

During 2012, four customers accounted for 50% of our oil and gas production revenues. During 2011, three customers accounted for 45% of our oil and gas production revenues. During 2010, two customers accounted for 25% of our oil and gas production revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results of operations.

We enter into hedging transactions with unaffiliated third parties for portions of our production revenues to achieve more predictable cash flows and to reduce our exposure to fluctuations in commodities prices. For a more detailed discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Our natural gas is transported through our own and third party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party gatherer, processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our gas before we can transport it. We contract with third parties to process our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser that has contracted for pipeline capacity. These agreements are subject to the limitations discussed above in this paragraph. Effective January 1, 2013, we modified our gas processing agreement with the processor

 

- 18 -


of a portion of our natural gas in the Gibson Gulch area in the Piceance Basin to take title to NGLs processed under the agreement. As a result, we plan to record those NGLs in our reserves and to separately report production of NGLs beginning in 2013.

Our oil production is collected in tanks and sold to third parties that collect the oil in trucks and transport it to pipelines, rail terminals and refiners. We sell our oil production to a variety of purchasers under monthly, annual or multi-year terms. Our oil contracts are priced either off of New York Mercantile Exchange (“NYMEX”) or area oil posting with quality, location or transportation differentials. We contract only for volumes that have been produced.

The following table sets forth information about material long-term firm transportation contracts for pipeline capacity and firm processing contracts, both of which typically require a demand charge and firm sales contracts. We source the gas to meet these commitments from our producing properties. At the time we entered into these commitments, we estimated that our production, and the production of joint interest owners that we market, would be sufficient to meet these commitments. Under firm gathering, transportation and processing contracts, we are obligated to deliver minimum daily gas volumes, or pay the respective gathering, transportation or processing fees for any deficiencies in deliveries. With the firm sales contracts, we are obligated to sell minimum daily gas volumes. If the volumes are not met, we will bear our proportionate share of costs related to the volume shortfall.

 

Type of Arrangement

  

Pipeline System /Location

  

Deliverable Market

   Gross Deliveries (MMBtu/d)      Term  

Firm Sales

   White River Hub    Rocky Mountains      10,000         11/12 – 03/13   

Firm Sales

   White River Hub    Rocky Mountains      10,000         11/12 – 03/13   

Firm Sales

   White River Hub    Rocky Mountains      5,000         11/12 – 03/13   

Firm Sales

   Rockies Express    Northeast      10,000         11/12 – 03/13   

Firm Sales

   Rockies Express    Northeast      15,000         11/12 – 03/13   

Firm Sales

   Cheyenne Hub    Rocky Mountains      5,000         02/13 – 03/13   

Firm Sales

   Questar Pipeline    Rocky Mountains      5,000         11/12 – 03/13   

Firm Sales

   Questar Pipeline    Rocky Mountains      12,000         11/12 – 03/13   

Firm Sales

   Questar Pipeline    Rocky Mountains      20,000         11/12 – 03/13   

Firm Sales

   Ruby Pipeline    West Coast      25,000         11/12 – 03/13   

Firm Gathering

   Summit Midstream    Rocky Mountains      Varies         01/11 – 12/20   

Firm Transport

   WIC Kanda    Rocky Mountains      15,000         12/08 – 10/23   

Firm Transport

   WIC Kanda    Rocky Mountains      65,000         11/10 – 10/20   

Firm Transport

   WIC Kanda(1)    West Coast      50,000         08/11 – 07/21   

Firm Transport

   Questar Pipeline    Rocky Mountains      12,000         11/05 – 10/15   

Firm Transport

   Questar Pipeline    Rocky Mountains      25,000         01/07 – 12/16   

Firm Transport

   Questar Pipeline    Rocky Mountains      25,000         11/07 – 10/17   

Firm Transport

   Rockies Express    Northeast      25,000         01/08 – 06/19   

Firm Transport

   Ruby Pipeline    West Coast      50,000         08/11 – 07/21   

Firm Gathering

   Three Rivers Gathering LLC    Rocky Mountains      70,000         06-09 – 05/20   

Firm Processing

   Questar Gas Management    Rocky Mountains      70,000         06/09 – 05/20   

Firm Processing

   Questar Field Services    Rocky Mountains      50,000         08/06 – 08/16   

 

(1) This contract was taken out in conjunction with the Ruby Pipeline contract; and therefore, has an end date of ten years from the in-service date of the Ruby Pipeline.

 

- 19 -


Hedging Activities

We have an active commodity hedging program, the purpose of which is to mitigate the risks of volatile prices of natural gas, NGLs and oil. Typically, we intend to hedge approximately 50% to 70% of our oil, NGLs and natural gas production on a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments with counterparties that we believe are creditworthy. We currently have hedged approximately 70% of our expected 2013 production and 30% of our expected 2014 production at price levels that provide some economic certainty to our capital investments. To date 10 of our 17 lenders (or affiliates of lenders) under our credit facility are also hedging counterparties. We are not required to post collateral for these hedges other than the security for our credit facility. For additional information on our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Competition

The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of proved oil and gas reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and diversified energy companies and other independent operators that have larger financial, human and technological resources than we do.

We compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect of these competitive factors cannot be predicted.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work for significant defects. To the extent title opinions or other investigations reflect title defects on those properties; we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we utilize methods consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire satisfactory title to our producing properties. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of our properties or affect the carrying value of the properties.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the spring and fall months and increases during the summer and winter months. Seasonal anomalies such as mild winters or cool summers sometime lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during lower demand periods. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in certain areas of the Rockies. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

 

- 20 -


Environmental Matters and Regulation

General. Our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our operations are subject to the same environmental laws and regulations as other companies in the oil and gas exploration and production industry. These laws and regulations:

 

   

require the acquisition of various permits before drilling commences;

 

   

require the installation of expensive pollution control equipment;

 

   

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

 

   

limit or prohibit drilling activities on lands lying within environmentally sensitive areas, wilderness, wetlands and other protected areas;

 

   

require measures to prevent pollution from current operations, such as materials and waste management, transportation and disposal requirements;

 

   

require measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

 

   

impose substantial penalties for any non-compliance with federal, state and local laws and regulations;

 

   

impose substantial liabilities for any pollution resulting from our operations;

 

   

with respect to operations affecting federal lands or leases, require time consuming environmental analysis with uncertain outcomes;

 

   

expose us to litigation by environmental and other special interest groups; and

 

   

impose certain compliance and regulatory reporting requirements.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost and timing of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.

We believe that we substantially are in compliance with and have complied, with all applicable environmental laws and regulations. We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with governmental regulations. We believe that our continued compliance with existing requirements have been accounted for and will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of any more stringent future laws and regulations at this time. For the year ended December 31, 2012, we did not incur any material capital expenditures for remediation or retrofit of pollution control equipment at any of our facilities.

The environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of the Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental

 

- 21 -


assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and project alternatives. If impacts are considered significant, the agency will prepare a more detailed Environmental Impact Statement. These environmental analyses are made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that trigger the requirements of NEPA. Certain federal permits on non-federal lands may also trigger NEPA requirements. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and on the disposal of non-hazardous wastes. Under the oversight of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with RCRA or corresponding state programs. RCRA also imposes cleanup liability related to the mismanagement of regulated wastes. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent, non-hazardous waste provisions, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.”

We believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we have held, and continue to hold, all necessary and up-to-date approvals, permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes strict, joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be potentially responsible for a release or threatened release of a “hazardous substance” into the environment. These persons may include current and past owners or operators of a disposal site, or site where the release or threatened release of a “ hazardous substance” occurred, and companies that disposed of or arranged for the disposal of the hazardous substance at such sites. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims under CERCLA and/or state common law for cleanup costs, personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, could be subject to CERCLA. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These prescriptions also prohibit the discharge of dredge and fill material in regulated waters, including jurisdictional wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and

 

- 22 -


state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with the terms thereof. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development.

Air Emissions. The Federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. Most of our facilities are now required to obtain permits before work can begin, and existing facilities are often required to incur capital costs in order to maintain compliance with those permits. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. The EPA has deemed carbon dioxide (“CO2”) and other greenhouse gases to be a danger to public health, which is leading to regulation in a manner similar to other pollutants. The EPA now requires reporting of greenhouse gases, such as CO2 and methane, from operations. The EPA also issued air requirements specific to the oil and gas industry, including air standards for natural gas wells that are hydraulically fractured. These regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining permits has the potential to delay the development of oil and natural gas projects.

Climate Change. The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February 2005 and requires all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The United States has not ratified the Protocol, and the U.S. Congress has not passed proposed legislation directed at reducing greenhouse gas emissions. However, there is increasing public pressure from environmental groups and some states for the United States to develop a national program for regulating greenhouse gas emissions, and several states have already adopted regulations or announced initiatives focused on decreasing or stabilizing greenhouse gas emissions associated with industrial activity, primarily CO2 emissions from power plants. The EPA has also taken certain regulatory actions to address issues related to climate change. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely CO2 and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could impact our future operations. Our operations are not currently adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions could impact our business. However, future laws or regulations could result in substantial expenditures or reduced demand for oil or natural gas.

Homeland Security. Legislation continues to be introduced in Congress, and development of regulations continues in the Department of Homeland Security and other agencies, concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, federal, state, local, and Native American tribes are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply.

 

- 23 -


Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production. Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribes also regulate one or more of the following:

 

   

the location of wells;

 

   

the method of drilling and casing wells;

 

   

the rates of production or “allowables;”

 

   

the surface use and restoration of properties upon which wells are drilled and other third parties;

 

   

wildlife management and protection;

 

   

the protection of archeological and paleontological resources;

 

   

property mitigation measures;

 

   

the plugging and abandoning of wells; and

 

   

notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws can establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state and Native American tribe generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Hydraulic Fracturing. Our completion operations are subject to regulation, which may increase in the short- or long-term. The well completion technique known as hydraulic fracturing is used to stimulate production of natural gas and oil has come under increased scrutiny by the environmental community, and local, state and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate oil and natural gas production. We use this completion technique on substantially all our wells other than the coalbed methane wells we sold in 2012.

Under the direction of Congress, the EPA has undertaken a study of the effect of hydraulic fracturing on drinking water and groundwater. The EPA has also announced its plan to propose pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations. Congress may consider legislation to amend the Federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have issued similar disclosure rules. Several environmental groups have also petitioned the EPA to extend toxic release reporting requirements under the Emergency Planning Community Right-to-Know Act to the oil and gas extraction industry. In addition, the Department of the Interior has proposed expanded or new regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes many of the lands on which we conduct or plan to conduct operations. Furthermore, moratoria on hydraulic fracturing have been imposed in certain areas in states where we do not have operations and legislation has been proposed at local, state and federal levels.

 

- 24 -


Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale or resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.

FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes may have on our natural gas-related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering services, which occur upstream of jurisdictional transmission services, are regulated by state agencies. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.

Operations on Native American Reservations. A portion of our leases in the Uinta and San Juan Basins are, and some of our future leases in this and other areas may be, regulated by Native American tribes. In addition to regulation by various federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations applies to lessees, operators and other parties within the boundaries of Native American reservations. Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service, the Bureau of Indian Affairs, the Bureau of Land Management, or BLM, and the EPA, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, tribal employment and tribal contractor preferences and numerous other matters.

Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and Bureau of Land Management. However, each Native American tribe is a sovereign nation and has the right to enact and enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native American tribal members and numerous other conditions that apply to lessees, operators and contractors conducting operations within the boundaries of a Native American reservation. Further, lessees and operators within a Native American reservation are subject to the Native American tribal court system, unless there is a specific waiver of sovereign immunity by the Native American tribe allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal or state court.

Therefore, we are subject to various laws and regulations pertaining to Native American tribal surface ownership, Native American oil and gas leases, fees, taxes and other burdens, obligations and issues unique to oil and gas ownership and operations within Native American reservations. One or more of these requirements, or

 

- 25 -


delays in obtaining necessary approvals or permits pursuant to these regulations, may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project on those lands.

Employees

As of January 25, 2013, we had 344 employees of whom 195 work in our Denver office and 149 work in our field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.

Offices

As of December 31, 2012, we leased approximately 81,833 square feet of office space in Denver, Colorado at 1099 18th Street, where our principal offices are located. The lease for our Denver office expires in March 2019. We also own field offices in Roosevelt, Utah and Silt, Colorado, and we lease a field office in Greeley, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

Website and Code of Business Conduct and Ethics

Our website address is http://www.billbarrettcorp.com. We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC via EDGAR and posted at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines and the charters of our Audit Committee, Compensation Committee, Reserves Committee and Nominating and Corporate Governance Committee are posted on our website at http://www.billbarrettcorp.com and are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 1099 18th Street, Suite 2300, Denver, Colorado 80202. We intend to disclose on our website any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K. This Annual Report on Form 10-K and our website contain information provided by other sources that we believe are reliable. We cannot assure you that the information obtained from other sources is accurate or complete. No information on our website is incorporated by reference herein or deemed to be part of this Annual Report on Form 10-K.

Annual CEO Certification

As required by New York Stock Exchange rules, on May 18, 2012, we submitted an annual certification signed by our Chief Executive Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.

 

- 26 -


GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and gas industry:

2-D seismic. The standard acquisition technique used to image geologic formations over a broad area. Data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. 2-D seismic data produces an image of a single vertical plane of sub-surface data.

3C 3-D seismic. A three dimensional seismic survey employing three-component geophones. These multi-component geophones record three orthogonal components of ground motion and provide information about shear waves that are unobtainable by conventional 3-D seismic surveys.

3-D seismic. Acoustical reflection data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Basin-centered gas. A regional, abnormally pressured, gas-saturated accumulation in low-permeability reservoirs lacking a down-dip water contact.

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Coalbed methane or CBM. Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and can be produced into a pipeline.

Completion. Installation of permanent equipment for production of oil and gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Curtailments. The delivery of gas below contract entitlements due to system restrictions.

Delineation. The process of drilling wells away from, or that is removed from, a known point of well control.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

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

Down-dip. The occurrence of a formation at a lower elevation than a nearby area.

 

- 27 -


Drill-to-earn. The process of earning an interest in leasehold acreage by drilling a well pursuant to a farm-in, exploration, or other agreement.

Dry hole or Dry well. An exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Environmental Assessment or EA. A study that can be required pursuant to federal law prior to drilling a well.

Environmental Impact Statement or EIS. A more detailed study that can be required pursuant to federal law of the potential direct, indirect and cumulative impacts of a project that may be made available for public review and comment.

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

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal Drilling. A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill bit to drill horizontally within a designated zone typically defined as the prospective pay zone to be completed for oil and or gas.

Hydraulic fracturing. The injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas and oil production.

Identified drilling locations. Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. Thousand barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

Mcf. Thousand cubic feet of natural gas.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBbls. Million barrels of crude oil or other liquid hydrocarbons.

MMBoe. Million barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

 

- 28 -


MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMcfe/d. MMcfe per day.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

NGLs. Natural gas liquids.

Play. A term used to describe an accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area expanse.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Potentiometric surface. An imaginary surface defined by the level to which water in an aquifer would rise due to the natural pressure in the rocks.

Productive well. An exploratory, development, or extension well that is not a dry well.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves or PDP. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.

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

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Resource Management Plan or RMP. A document that describes the Bureau of Land Management’s intended uses of lands that are under its jurisdiction.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Shale gas. Considered to be an unconventional accumulation of natural gas where the gas is recovered from extremely low permeability shales, generally through the use of horizontal drilling and massive hydraulic fracturing.

 

- 29 -


Standardized Measure. The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.

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

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

Item 1A. Risk Factors.

Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or that we currently consider immaterial also may adversely affect our Company.

Risks Related to the Oil and Natural Gas Industry and Our Business

Oil and natural gas prices are volatile and a decline in oil, natural gas liquids and natural gas prices can significantly affect our financial results, impede our growth and result in downward adjustments in our estimated proved oil and gas reserves.

Our revenue, profitability and cash flow depend upon the prices and demand for oil, NGLs and natural gas. The markets for these commodities are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil, NGL and natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil, NGL and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

   

the domestic and foreign supply of oil and natural gas;

 

   

economic conditions in the United States, and the level of consumer product demand;

 

   

domestic and foreign governmental regulations;

 

   

variations between product prices at sales points and applicable index prices;

 

   

overall domestic and global economic conditions;

 

   

political and economic conditions in oil producing countries, including the Middle East and South America;

 

   

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

   

weather conditions;

 

   

technological advances affecting energy consumption;

 

   

proximity and capacity of oil and gas pipelines, refineries and other transportation and processing facilities; and

 

   

the price and availability of alternative fuels.

 

- 30 -


Lower oil, NGL and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial 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 or development results deteriorate, successful efforts accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured or underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

 

   

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

 

   

abnormally pressured or structured formations;

 

   

mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

 

   

fires, explosions and ruptures of pipelines;

 

   

personal injuries and death; and

 

   

natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

 

   

injury or loss of life;

 

   

damage to and destruction of property and equipment;

 

   

damage to natural resources due to underground migration of hydraulic fracturing fluids or other fluids or gases;

 

   

pollution and other environmental damage, including spillage or mishandling of recovered hydraulic fracturing fluids and produced water;

 

   

regulatory investigations and penalties;

 

   

suspension of our operations; and

 

   

repair and remediation costs.

An example of the occurrence of these described risks is the fire and related injuries and damage at our Dry Canyon compressor station as described above in “Items 1 and 2. Business and Properties — Business — West Tavaputs Area”.

We have elected, and may in the future elect, not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. For example, we do not carry business interruption insurance for these reasons. In addition, pollution and environmental risks generally are not fully insurable. The

 

- 31 -


occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations and overall financial condition.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

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

Our drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We acquire significant amounts of unproved property in order to attempt to further our exploration and development efforts. Drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. From time to time, we may seek industry partners to help mitigate our risk on certain exploration prospects. We cannot guarantee you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, that we will recover all or any portion of our investment in such unproved property or wells, or that we will succeed in bringing on additional partners.

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether oil or natural gas is present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Drilling results in our shale plays may be more uncertain than in other shale plays that are more mature and have longer established drilling and production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in our shale prospects. As a result, we may incur future dry hole costs and or impairment charges due to any of these factors.

We are subject to complex federal, state, tribal, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business and the recording of proved reserves.

Our exploration, development, production and marketing operations are subject to extensive environmental regulation at the federal, state and local levels including those governing emissions to air, wastewater discharges, hazardous and solid wastes, remediation of soil, protection of surface and groundwater, and preservation of

 

- 32 -


natural resources. In addition, a portion of our leases in the Uinta Basin are, and some of our future leases may be, regulated by Native American tribes. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells and related facilities. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to state regulation of oil and natural gas production and Native American tribes conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling and other permits from state, local and Native American tribal authorities. Delays in obtaining regulatory approvals or drilling and other permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs, could have a material adverse effect on our ability to explore on or develop our properties. In addition, if we do not reasonably believe that we can obtain the drilling permits in a timely fashion covering locations for which we recorded proved undeveloped reserves, we may be required to write down the level of our proved reserves. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells, larger operating areas and other aspects of their businesses. See “Items 1 and 2. Business and Properties — Business — Operations — Environmental Matters and Regulation” and “Items 1 and 2. Business and Properties — Business — Operations — Other Regulation of the Oil and Gas Industry.”

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

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

The ability of our lenders to fund their lending obligations under our revolving credit facility may be limited, which would affect our ability to fund our operations.

Our revolving credit facility has commitments from 17 lenders. If credit markets become turbulent as a result of an economic downturn, delayed economic recovery or other factors, our lenders may become more restrictive in their lending practices or may be unable to fund their commitments, which would limit our access to

 

- 33 -


capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and potentially losses.

A U.S. and global economic downturn could have a material adverse effect on our business and operations.

Any or all of the following may occur as a result if a crisis arises in the global financial and securities markets and resulting economic downturn:

 

   

The economic slowdown could lead to lower demand for oil and natural gas by individuals and industries, which in turn has resulted and could continue to result in lower prices for the oil and natural gas sold by us, lower revenues and possibly losses. This is exacerbated by increases in gas supply resulting from increases in U.S. gas production.

 

   

The lenders under our revolving credit facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and possibly losses.

 

   

We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower production levels and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.

 

   

The losses incurred by financial institutions as well as the insolvency of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy or being placed in conservatorship or receivership may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially, adversely affected.

 

   

Our credit facility bears floating interest rates based on the London Interbank Offer Rate, or LIBOR. As banks were reluctant to lend to each other to avoid risk, LIBOR increased to unprecedented spread levels in 2008. Such increases caused and may in the future cause higher interest expense for unhedged levels of LIBOR-based borrowings.

 

   

Our credit facility requires the lenders to redetermine our borrowing base semi-annually. The redeterminations are based on our proved reserves and hedge position based on price assumptions that our lenders require us to use to calculate reserves pursuant to the credit facility. The lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base due to lower commodities and futures prices and our borrowing base could be reduced. This would reduce our funds available to borrow.

 

   

Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.

 

   

Bankruptcies of purchasers of our oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.

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

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and

 

- 34 -


acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with sales of our equity and debt securities, proceeds from bank borrowings, sales of properties and cash generated by operations. We intend to finance our capital expenditures with cash flow from operations, sale of properties and our existing financing arrangements. Our cash flow from operations and access to capital is subject to a number of variables, including:

 

   

our proved reserves;

 

   

the level of oil and natural gas we are able to produce from existing wells;

 

   

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

 

   

the costs required to operate production;

 

   

our ability to acquire, locate and produce new reserves;

 

   

global credit and securities markets;

 

   

the ability and willingness of lenders and investors to provide capital and the cost of that capital; and

 

   

the interest of buyers in our properties and the price they are willing to pay for properties.

If our revenues or the borrowing base under our credit facility decreases as a result of lower oil and natural gas prices, 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 current or planned levels. We may, from time to time, need to seek additional financing. Our credit facility and senior note indentures place certain restrictions on our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing.

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

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could prohibit certain projects or result in materially increased costs and additional operating restrictions or delays because of the significance of hydraulic fracturing in our business.

Hydraulic fracturing is a well completion practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Nearly all of our future drilling projects will require hydraulic fracturing. If the hydraulic fracturing process is prohibited or significantly regulated or restricted, we would lose the ability to (i) drill and complete the projects for such proved reserves and (ii) maintain the associated acreage, which would have a material adverse effect on our future business, financial condition, operating results and prospects.

The hydraulic fracturing process is currently regulated by state oil and gas commissions, although local initiatives have been proposed to further regulate or ban the process. The EPA asserting its authority under the Safe Drinking Water Act (“SDWA”), issued a draft guidance that proposes to require facilities to obtain permits when using diesel fuel in hydraulic fracturing operations. That guidance was issued for public review and comment in 2012 and is expected to be finalized in 2013. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without an Underground Injection Control (“UIC”) permit. Industry groups have filed suit challenging the EPA’s recent decisions as a “final agency action” and, thus, in violation of the notice-and-comment rulemaking

 

- 35 -


procedures of the Administrative Procedure Act. In November 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. In 2012, the EPA released a progress report on this study. A final report is not expected until late 2014.

In 2011, a committee of the House of Representatives announced its findings from a year-long investigation of hydraulic fracturing practices and urged the enactment of legislation that would mandate more stringent regulation of the hydraulic fracturing industry. Further, certain members of Congress have called upon: (i) the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; (ii) the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and (iii) the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

The Shale Gas Subcommittee of the Secretary of Energy Advisory Board released a report on August 11, 2011, proposing recommendations to reduce the potential environmental impacts from shale gas production. These ongoing or proposed 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. The U.S. Department of the Interior is developing proposed federal regulations to require the disclosure of the chemicals used in the fracturing process on public lands and will serve as a model for state regulation regarding the process.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to regulations adopted by the Colorado Oil and Gas Conservation Commission (“COGCC”), the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the COGCC and the public beginning in April 2012. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

The adoption of these or any other new laws or regulations that significantly restrict hydraulic fracturing could make it more difficult or costly for us to drill and produce from conventional or tight formations as well as make it easier for third parties opposing drilling in general or the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal, state or local legislation or regulations governing hydraulic fracturing are enacted or adopted.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these assumptions will materially affect the quantities of our reserves.

Underground accumulations of oil and natural gas cannot be measured in an exact way. Oil and natural gas reserve engineering requires estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect.

 

- 36 -


Our estimates of proved reserves are determined at prices and costs at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates of reserves. We prepare our own estimates of proved reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see “Items 1 and 2. Business and Properties—Oil and Gas Data—Proved Reserves” and “Supplementary Information to Consolidated Financial Statements—Supplementary Oil and Gas Information (unaudited)—Analysis of Changes in Proved Reserves” in this Annual Report on Form 10-K.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, natural gas and oil prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may differ materially differ from those presently identified, which could adversely affect our business.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas and, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons. We are employing 3C 3-D seismic technology to evaluate certain of our projects. The implementation and practical use of 3C 3-D seismic technology is relatively new, unproven and unconventional, which can lessen its effectiveness, at least in the near term, and increase our costs. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3-D data without having an opportunity to attempt to benefit from those expenditures.

 

- 37 -


Substantially all of our producing properties are located in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.

Our operations have been focused on the Rockies, 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 oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation and processing, and any resulting delays or interruptions of production from existing or planned new wells.

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

Oil and natural gas operations in the Rockies are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.

One of our strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. Our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remaining properties for reserve potential. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.

Our hedging activities could result in financial losses or could reduce our income.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a portion of our production revenues. Hedging arrangements for a portion of our production revenues expose us to the risk of financial loss in some circumstances, including when:

 

   

there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;

 

   

there is a change in the mark to market value of our derivatives; or

 

   

the counterparty to the hedging contract defaults on its contractual obligations.

In addition, these types of hedging arrangements limit the benefit we would receive from increases in commodities prices and may expose us to cash margin requirements if we hedge with counterparties who are not parties to our credit facility.

Our counterparties are financial institutions that are lenders under our credit facility or affiliates of such lenders. The risk that a counterparty may default on its obligations was heightened by the financial sector crisis

 

- 38 -


of 2008-2009, and losses incurred by many banks and other financial institutions, including some of our counterparties or their affiliates. These losses may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which would reduce our revenues from hedges at a time when we are also receiving a lower price for our production revenues, thus triggering the hedge payments. As a result, our financial condition could be materially adversely affected.

Federal legislation may decrease our ability, and increase the cost, to enter into hedge transactions.

The Dodd-Frank Wall Street Reform and Consumer Protective Act (“Dodd-Frank”) was signed into law in July 2010. Dodd-Frank regulates derivative transactions, including our commodity derivative swaps. Derivatives final rules were enacted in 2012 and the effect of such rules on our business is currently uncertain. However, as a commercial end user using derivatives to manage commercial risks, we are exempt from posting collateral requirements and mandatory trading on a centralized exchange. We expect to be able to continue to trade with our counterparties, which all are or have been lenders or affiliates of lenders in our credit facility, albeit with a separate capitalized subsidiary of the lender. We expect that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased capital costs of bank subsidiaries. Decreasing our ability to enter into hedging transactions would expose us to additional risks related to commodity price volatility and 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.

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 oil and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties. An economic downturn, a delayed economic recovery and the European sovereign debt crisis further increase these risks.

We face risks related to rating agency downgrades.

If one or more rating agencies downgrades our outstanding debt, raising debt capital could become more difficult and more costly and we may be required to provide collateral or other credit support to certain counterparties. Providing credit support increases our costs and can limit our liquidity.

Compliance with Environmental Protection Agency (“EPA”) regulations is expected to become increasingly costly and may lead to our inability to obtain permits necessary to construct and operate new facilities.

The EPA regulates the level of ozone in ambient air and may propose to lower the allowed level of ozone in the future. Because of climate processes, most of the Rockies, where we operate, have higher levels of ozone. As a result of these existing and possible more stringent standards, we may not be able to obtain permits necessary to construct and operate new facilities, or, if we obtain the permits, the added costs to comply with the permit requirements could substantially increase our operating expenses, which would reduce our profits or make certain operations uneconomical.

Possible additional regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas.

Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases”, including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February

 

- 39 -


2005 and requires all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The United States has not ratified the Protocol, and the U.S. Congress has not passed proposed legislation directed at reducing greenhouse gas emissions. However, there is increasing public pressure from environmental groups and some states for the United States to develop a national program for regulating greenhouse gas emissions, and several states have already adopted regulations or announced initiatives focused on decreasing or stabilizing greenhouse gas emissions associated with industrial activity, primarily CO2 emissions from power plants. The EPA also has taken certain regulatory actions to address issues related to climate change. Passage of state or federal climate control legislation or other regulatory initiatives or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for oil and gas.

Possible additional regulation could have an adverse effect on our operations.

Proposed energy legislation and new regulations, driven in part by the Macondo oil spill in the Gulf of Mexico in 2010, could limit our ability to operate on federal lands, delay access to federal lands, and increase the cost of our operations. These include the Consolidated Land, Energy, and Aquatic Resources Act (CLEAR), the Clean Energy Jobs and Oil Company Accountability Act, the Blowout Prevention Act, and public land leasing reforms. The inability to access federal lands, as well as delays and the increased cost of operating on federal lands could result in losses of revenues, increased costs and devaluing of our assets.

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

As an oil and natural gas producer, we face various security threats, including cyber-security 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 facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to 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 success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.

 

- 40 -


Risks Related to Our Common Stock

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.

Delaware corporate law and our current certificate of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:

 

   

giving the board the exclusive right to fill all board vacancies;

 

   

requiring special meetings of stockholders to be called only by the board;

 

   

requiring advance notice for stockholder proposals and director nominations;

 

   

prohibiting stockholder action by written consent;

 

   

prohibiting cumulative voting in the election of directors; and

 

   

allowing for authorized but unissued common and preferred shares, including shares used in our shareholder rights plan.

These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

Risks Related to our Senior Notes, Convertible Notes, Lease Financing Obligations and Amended Credit Facility

We may not be able to generate enough cash flow to meet our debt obligations, including our obligations and commitments under our senior notes, our convertible senior notes, our lease financing obligations and our revolving credit facility.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may be insufficient to meet our debt obligations and commitments, including our 9.875% Senior Notes due 2016 (“9.875% Senior Notes”) and our 7.625% Senior Notes due 2019 (“7.625% Senior Notes”), our 5% Convertible Senior Notes due 2028 (“Convertible Notes”), our 7.0% Senior Notes due 2022 (“7.0% Senior Notes”), our lease financing obligations, and our revolving credit facility (“Amended Credit Facility”). Any insufficiency could negatively impact our business. A range of economic, competitive, business, and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to repay our debt. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

As of December 31, 2012, the total outstanding principal amount of our long term indebtedness was approximately $1,173.0 million, and we had approximately $799.0 million in additional borrowing capacity under our Amended Credit Facility, which, if borrowed, would be secured debt effectively senior to the Senior Notes and Convertible Notes to the extent of the value of the collateral securing that indebtedness. Our Amended Credit Facility has $825.0 million in commitments. The borrowing base is dependent on our proved reserves and was, as of December 31, 2012, $825.0 million based on our December 31, 2012 proved reserves and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. As of December 31, 2012, the outstanding principal balance under our Amended Credit Facility was $0.0 million.

 

- 41 -


If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake one or more alternative financing plans, such as:

 

   

refinancing or restructuring our debt;

 

   

selling assets;

 

   

reducing or delaying capital investments; or

 

   

seeking to raise additional capital.

However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Our debt could have important consequences. For example, it could:

 

   

increase our vulnerability to general adverse economic and industry conditions;

 

   

limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;

 

   

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

 

   

impair our ability to obtain additional financing in the future; and

 

   

place us at a competitive disadvantage compared to our competitors that have less debt.

In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our convertible notes and our senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.

Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.

Our Amended Credit Facility contains a number of significant covenants in addition to covenants restricting the incurrence of additional debt. Our Amended Credit Facility requires us, among other things, to maintain certain financial ratios or reduce our debt. These restrictions also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indenture governing the notes and our Amended Credit Facility impose on us.

Our Amended Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Amended Credit Facility. Any increase in the borrowing base requires the consent of the lenders holding 98% of the commitments. If the required lenders do not agree on an increase, then the borrowing base will be the lowest borrowing base acceptable to the required number of lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately or we must pledge other oil and natural gas 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 mandatory principal prepayments required under the Amended Credit Facility.

 

- 42 -


A breach of any covenant in our Amended Credit Facility or the agreements and indentures governing our other indebtedness would result in a default under that agreement or indenture after any applicable grace periods. A default, if not waived, could result in acceleration of the debt outstanding under the agreement and in a default with respect to, and an acceleration of, the debt outstanding under other debt agreements. The accelerated debt would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt or take other actions to pay accelerated debt. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Risks Relating to Tax

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.

President Obama has proposed eliminating certain key U.S. federal income tax deductions and credits currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to:

 

   

the repeal of the percentage depletion allowance for oil and natural gas properties;

 

   

the elimination of current deductions for intangible drilling and development costs;

 

   

the elimination of the deduction for certain U.S. production activities; and

 

   

an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether any of the foregoing changes will be enacted or how soon any such changes could become effective. Any such change could negatively impact our financial condition and results of operations by increasing the costs we incur, which in turn could make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

Item 1B. Unresolved Staff Comments.

Not applicable.

Item 3. Legal Proceedings.

We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

Item 4. Mine Safety Disclosures.

Not applicable.

 

- 43 -


PART II

 

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

Market For Registrant’s Common Equity.

Our common stock is listed on the New York Stock Exchange under the symbol “BBG.”

The range of high and low sales prices for our common stock for the two most recent fiscal years as reported by the New York Stock Exchange was as follows:

 

     High      Low  

2012

     

First Quarter

   $ 36.44       $ 25.00   

Second Quarter

     26.38         15.42   

Third Quarter

     27.01         18.10   

Fourth Quarter

     26.13         16.84   

2011

     

First Quarter

   $ 42.85       $ 35.45   

Second Quarter

     46.86         39.36   

Third Quarter

     52.13         36.24   

Fourth Quarter

     44.94         31.96   

On January 25, 2013, the closing sales price for our common stock as reported by the NYSE was $17.03 per share.

Holders. On December 31, 2012, the number of holders of record of our common stock was 142.

Dividends. We have not paid any cash dividends since our inception. Because we anticipate that all earnings will be retained for the development of our business and our Amended Credit Facility and Senior Notes prohibit the payment of cash dividends, we do not expect that any cash dividends will be paid on our common stock for the foreseeable future.

Unregistered Sales of Securities. There were no sales of unregistered equity securities during the year ended December 31, 2012.

Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2012:

 

Period

   Total
Number of
Shares (1)
     Weighted
Average Price
Paid Per
Share
     Total Number of Shares
(or Units) Purchased as
Part of Publicly
Announced Plans or
Programs
     Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
 

October 1 – 31, 2012

     0         N/A         0        0  

November 1 – 30, 2012

     1,292       $ 17.94         0        0  

December 1 – 31, 2012

     3,238       $ 18.59         0        0  
  

 

 

       

 

 

    

 

 

 

Total

     4,530       $ 18.40             0            0  
  

 

 

       

 

 

    

 

 

 

 

(1) Represents shares delivered by employees to satisfy the exercise price of stock options and tax withholding obligations in connection with the exercise of stock options and shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of restricted common stock issued pursuant to our employee incentive plans.

 

- 44 -


Stockholder Return Performance Presentation

As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:

 

1. $100 was invested in our common stock on December 31, 2007, and $100 was invested in each of the Standard & Poors 500 Index and the Standard & Poors MidCap 400 Index-Energy Sector at the closing price on December 31, 2007.

 

2. Dividends are reinvested on the ex-dividend dates.

 

LOGO

 

    December 31,
2007
    December 31,
2008
    December 31,
2009
    December 31,
2010
    December 31,
2011
    December 31,
2012
 

BBG

  $ 100      $ 50      $ 74      $ 98      $ 81      $ 42   

S&P MidCap 400- Energy

    100        43        78        102        91        106   

S&P 500

    100        63        80        92        94        109   

 

Item 6. Selected Financial Data.

The following table presents our selected historical financial data for the years ended December 31, 2012, 2011, 2010, 2009 and 2008. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere in this Annual Report on Form 10-K.

 

- 45 -


Selected Historical Financial Information

The consolidated statement of operations information for the years ended December 31, 2012, 2011 and 2010 and the balance sheet information as of December 31, 2012 and 2011 are derived from our audited consolidated financial statements included elsewhere in this report. The consolidated statement of operations information for the years ended December 31, 2009 and 2008 and the balance sheet information at December 31, 2010, 2009 and 2008 are derived from audited consolidated financial statements that are not included in this report. The information in this table should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included herein.

 

     Year Ended December 31,  
     2012     2011     2010     2009     2008  
     (in thousands, except per share data)  

Statement of Operations Data:

          

Operating and other revenues

          

Oil and gas production(1)

   $ 700,639      $ 780,751      $ 708,452      $ 647,839      $ 605,881   

Other

     (444     4,873        591        4,891        4,110   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating and other revenues

     700,195        785,624        709,043        652,730        609,991   

Operating expenses:

          

Lease operating expense

     72,734        56,603        52,040        46,492        44,318   

Gathering, transportation and processing expense

     106,548        93,423        69,089        56,608        39,342   

Production tax expense

     25,513        37,498        32,738        13,197        44,410   

Exploration expense

     8,814        3,645        9,121        3,227        8,139   

Impairment, dry hole costs and abandonment expense

     67,869        117,599        44,664        52,285        32,065   

Depreciation, depletion and amortization

     326,842        288,421        260,665        253,573        206,316   

General and administrative expense(2)

     52,222        47,744        40,884        37,940        40,454   

Non-cash stock-based compensation expense(2)

     16,444        19,036        16,908        16,458        16,752   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     676,986        663,969        526,109        479,780        431,796   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     23,209        121,655        182,934        172,950        178,195   

Other income and expense:

          

Interest income and other income (expense)

     155        (397     402        438        2,036   

Interest expense

     (95,506     (58,616     (44,302     (30,647     (19,717

Commodity derivative gain (loss)

     72,759        (14,263     (10,579     (54,567     7,920   

Gain on extinguishment of debt

     1,601        0        0        0        0   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income and expense

     (20,991     (73,276     (54,479     (84,776     (9,761
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     2,218        48,379        128,455        88,174        168,434   

Provision for income taxes

     1,636        17,672        47,953        37,956        63,175   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 582      $ 30,707      $ 80,502      $ 50,218      $ 105,259   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income per common share:

          

Basic

   $ 0.01      $ 0.66      $ 1.78      $ 1.12      $ 2.37   

Diluted

   $ 0.01      $ 0.65      $ 1.75      $ 1.12      $ 2.34   

Weighted average common shares outstanding, basic

     47,194.7        46,535.6        45,217.6        44,723.1        44,432.4   

Weighted average common shares outstanding, diluted

     47,354.0        47,236.7        45,877.4        45,036.0        45,036.5   

 

- 46 -


    Year Ended December 31,  
    2012     2011     2010     2009     2008  
    (in thousands)  

Selected Cash Flow and Other Financial Data:

         

Net income

  $ 582      $ 30,707      $ 80,502      $ 50,218      $ 105,259   

Depreciation, depletion, impairment and amortization

    364,190        388,699        276,281        273,227        206,316   

Other non-cash items

    29,281        55,102        101,079        132,885        109,376   

Change in assets and liabilities

    (5,617     4,840        (10,674     24,414        (18,004
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

  $ 388,436      $ 479,348      $ 447,188      $ 480,744      $ 402,947   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures(3) (4)

  $ 962,573      $ 987,341      $ 473,268      $ 406,420      $ 601,115   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Oil and gas production revenues include the effects of cash flow hedging transactions.
(2) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Consolidated Statements of Operations for a total of $68.7 million, $66.8 million, $57.8 million, $54.4 million and $57.2 million for the years ended December 31, 2012, 2011, 2010, 2009 and 2008, respectively. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expense. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower non-cash stock-based compensation expense.
(3) Excludes future reclamation liability accruals of $7.5 million, $12.1 million, $1.3 million, negative $1.2 million and $8.2 million for the years ended December 31, 2012, 2011, 2010, 2009 and 2008, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $39.3 million, $21.0 million, $38.2 million, $35.9 million and $14.9 million for the years ended December 31, 2012, 2011, 2010, 2009 and 2008, respectively. Also includes furniture, fixtures and equipment costs of $6.9 million, $8.9 million, $2.1 million, $2.1 million and $4.9 million for the years ended December 31, 2012, 2011, 2010, 2009 and 2008, respectively.
(4) Not deducted from the amount are $325.3 million, $2.0 million, $2.9 million, $3.7 million and $2.4 million of proceeds received principally from the sale of interests in oil and gas properties during the years ended December 31, 2012, 2011, 2010, 2009 and 2008, respectively.

 

    As of December 31,  
    2012     2011     2010     2009     2008  
    (in thousands)  

Balance Sheet Data:

         

Cash and cash equivalents

  $ 79,445      $ 57,331      $ 58,690      $ 54,405      $ 43,063   

Other current assets

    148,894        189,012        148,958        125,634        270,311   

Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment

    2,584,979        2,383,196        1,796,288        1,639,212        1,548,633   

Other property and equipment, net of depreciation

    26,358        23,568        15,531        14,444        13,186   

Oil and natural gas properties held for sale, net of accumulated depreciation, depletion, amortization and impairment

    0        0        0        5,604        0   

Other assets

    29,773        34,823        19,033        26,824        119,300   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

  $ 2,869,449      $ 2,687,930      $ 2,038,500      $ 1,866,123      $ 1,994,493   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Current liabilities

  $ 213,133      $ 233,198      $ 165,957      $ 153,292      $ 225,794   

Long-term debt

    1,156,654        882,240        404,399        402,250        407,411   

Other long-term liabilities

    316,887        353,654        327,182        282,026        262,055   

Stockholders’ equity

    1,182,775        1,218,838        1,140,962        1,028,555        1,099,233   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and stockholders’ equity

  $ 2,869,449      $ 2,687,930      $ 2,038,500      $ 1,866,123      $ 1,994,493   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

- 47 -


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

Introduction

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in Item 1A “Risk Factors” above, which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

Overview

We develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value through profitable growth in cash flow, reserves and production by developing key existing development programs. With the decline in natural gas prices resulting from the increased supply over the past few years, we have shifted our focus to finding, acquiring and developing oil resources. Therefore, we will see a decrease in gas production in the coming year due to suspended gas drilling and natural production declines. We seek high quality development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGLs recovery at market prices and from the settlement of commodity hedges.

We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. Since inception, we have built our portfolio of properties primarily through acquisitions where we seek to add value through our geologic and operational expertise. Our acquisitions have included key assets in the Piceance (Colorado), Uinta (Utah), Denver-Julesburg (Colorado and Wyoming), Powder River (Wyoming) and Wind River (Wyoming) Basins in the Rocky Mountain region (the “Rockies”). We also may sell properties when the opportunity arises or when business conditions warrant, as demonstrated by the sale of our Wind River Basin and Powder River Basin properties and a portion of our Piceance Basin properties in 2012.

We are committed to exploring for, developing and producing oil and natural gas in a responsible and safe manner. We work diligently with environmental, wildlife and community organizations to ensure that our exploration and development activities are designed with all stakeholders in mind.

While there are currently no unannounced agreements for the acquisition of any material businesses or assets, future acquisitions could have a material impact on our financial condition and results of operations by increasing our proved reserves, production, and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, sales of properties, other indebtedness, and/or debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations. We are committed to not increasing overall debt at December 31, 2013 compared to total debt at December 31, 2012. As a result, expenditures in excess of cash flow and any acquisitions in 2013 would require us to sell other properties.

Historically, we have presented our production and reserve data for each of oil and natural gas. This is known as “two streams” reporting and is the manner in which the data in this Annual Report on Form 10-K is presented. For periods after January 1, 2013, we intend to report production and reserve data for each of oil, natural gas and NGLs. This is known as “three streams reporting”.

 

- 48 -


Because of our growth through acquisitions and, more recently, development of our properties and sale of non-core properties in 2012, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition past results are not indicative of future results.

The following table summarizes the estimated net proved reserves and related Standardized Measure for the years indicated. The Standardized Measure is not intended to represent the current market value of our estimated oil and natural gas reserves.

 

     Year Ended December 31,  
     2012     2011      2010  

Estimated net proved reserves (Bcfe)

     1,043.7        1,364.7         1,118.3   

Standardized Measure (1) (in millions)

   $ 1,166.7 (2)    $ 1,616.1       $ 1,132.4   

 

(1) December 31, 2012 was based on average prices of $2.56 CIG for natural gas and $91.21 WTI for oil using the current SEC requirements. December 31, 2011 was based on average prices of $3.93 CIG for natural gas and $92.71 WTI for oil using then-effective SEC requirements. December 31, 2010 was based on average prices of $3.95 CIG for natural gas and $75.96 WTI for oil using then-effective SEC requirements.
(2) The December 31, 2012 valuation is significantly reduced due to the December 2012 sales of our Wind River Basin and Powder River Basin (coalbed methane) properties and a partial interest in our Piceance Basin properties.

The following table summarizes the average sales prices received for natural gas and oil, before the effects of hedging contracts, for the years indicated:

 

     Year Ended December 31,  
     2012      2011      2010  

Natural gas (per Mcf)

   $ 4.00       $ 5.71       $ 5.26   

Oil (per Bbl)

   $ 79.39       $ 81.97       $ 67.93   

The following table summarizes the average sales prices received for natural gas and oil, after the effects of hedging contracts, for the years indicated:

 

     Year Ended December 31,  
     2012      2011      2010  

Natural gas (per Mcf)

   $ 5.07       $ 6.46       $ 6.74   

Oil (per Bbl)

   $ 84.96       $ 80.63       $ 69.91   

Commodity prices are inherently volatile and are influenced by many factors outside of our control. We plan our activities and capital budget using what we believe to be conservative sales price assumptions and our existing hedge position. Our strategic objective is to hedge 50% to 70% of our anticipated production on a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments. We currently have hedged approximately 70% of our expected 2013 production and 30% of our expected 2014 production at price levels that provide some economic certainty to our capital investments. We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.

Like all oil and gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a typical well naturally decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue

 

- 49 -


to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. See “ – Trends and Uncertainties – Regulatory Trends” below. The permitting and approval process has been more difficult in recent years than in the past due to more stringent rules, such as those enacted by the COGCC in 2009, and increased activism from environmental and other groups, which has extended the time it takes us to receive permits and other necessary approvals. Because of our relatively small size and concentrated property base, we can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we may be less able to shift drilling activities to areas where permitting may be easier, and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

Results of Operations

Year Ended December 31, 2012 Compared with Year Ended December 31, 2011

The following table sets forth selected operating data for the periods indicated:

 

    Year Ended
December 31,
    Increase (Decrease)  
  2012     2011     Amount     Percent  
  ($ in thousands, except per unit data)  

Operating Results:

       

Operating and other revenues

       

Oil and gas production

  $ 700,639      $ 780,751      $ (80,112     (10 )% 

Other

    (444     4,873        (5,317     (109 )% 
 

 

 

   

 

 

   

 

 

   

Total operating and other revenues

  $ 700,195      $ 785,624      $ (85,429     (11 )% 
 

 

 

   

 

 

   

 

 

   

Operating expenses

       

Lease operating expense

    72,734        56,603        16,131        28

Gathering, transportation and processing expense

    106,548        93,423        13,125        14

Production tax expense

    25,513        37,498        (11,985     (32 )% 

Exploration expense

    8,814        3,645        5,169        142

Impairment, dry hole costs and abandonment expense

    67,869        117,599        (49,730     (42 )% 

Depreciation, depletion and amortization

    326,842        288,421        38,421        13

General and administrative expense (1)

    52,222        47,744        4,478        9

Non-cash stock-based compensation expense (1)

    16,444        19,036        (2,592     (14 )% 
 

 

 

   

 

 

   

 

 

   

Total operating expenses

  $ 676,986      $ 663,969      $ 13,017        2
 

 

 

   

 

 

   

 

 

   

Production Data:

       

Natural gas (MMcf)

    101,486        97,856        3,630        4

Oil (MBbls)

    2,687        1,490        1,197        80

Combined volumes (MMcfe)

    117,608        106,796        10,812        10

Daily combined volumes (MMcfe/d)

    321        293        28        10

Average Prices (2):

       

Natural gas (per Mcf) (2)

  $ 5.07      $ 6.46      $ (1.39     (22 )% 

Oil (per Bbl)

    84.96        80.63        4.33        5

Combined (per Mcfe)

    6.32        7.05        (0.73     (10 )% 

Average Costs (per Mcfe):

       

Lease operating expense

  $ 0.62      $ 0.53      $ 0.09        17

Gathering, transportation and processing expense

    0.91        0.87        0.04        5

Production tax expense

    0.22        0.35        (0.13     (37 )% 

Depreciation, depletion and amortization (3)

    2.91        2.70        0.21        8

General and administrative expense (4)

    0.44        0.45        (0.01     (2 )% 

 

- 50 -


 

(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Consolidated Statements of Operations for a total of $68.7 million and $66.8 million for the years ended December 31, 2012 and 2011, respectively. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with non-cash stock-based compensation expense.
(2) Average prices shown in the table are net of the effects of all of our realized commodity hedging transactions. Natural gas average prices include the effect of NGL-related revenue.
(3) The DD&A per Mcfe as calculated based on the DD&A expense and MMcfe production data presented in the table for the year ended December 31, 2012 is $2.78. However, the DD&A rate per Mcfe for the year ended December 31, 2012 of $2.91, as presented in the table above, excludes production of 5,465 MMcfe, associated with our properties that were sold as of December 31, 2012.
(4) Excludes non-cash stock-based compensation expense as described in Note 1 above. This presentation is a non-GAAP measure. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Consolidated Statements of Operations, were $0.58 and $0.63 for the years ended December 31, 2012 and 2011, respectively.

Production Revenues and Volumes. Production revenues decreased to $700.6 million for the year ended December 31, 2012 from $780.8 million for the year ended December 31, 2011 due to a 19% decrease in oil and natural gas prices on a per Mcfe basis after the effects of realized cash flow hedges, offset by a 10% increase in production. The decrease in average price reduced production revenues by approximately $144.6 million, and the net increase in production added approximately $64.4 million of production revenues.

The year ended December 31, 2011 included settlements of $99.9 million from financial hedging instruments that were designated as cash flow hedges and excluded those that did not qualify, or were not designated, as cash flow hedges such as basis only and NGL swaps. The settlements from hedging instruments that were not designated as cash flow hedges were included in the line item commodity derivative gain (loss) within other income in the Consolidated Statements of Operations. See “–Commodity Derivative Gain (Loss)” below for more information related to the commodity derivative gain (loss) line item. We discontinued hedge accounting effective January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in accumulated other comprehensive income (“AOCI”) effective January 1, 2012 and will remain in AOCI until the underlying transaction occurs. As the underlying transaction occurs, these gains or losses are reclassified from AOCI into oil and gas production revenues. The amount reclassified to oil and gas production revenues was a gain of $81.2 million for the year ended December 31, 2012.

 

- 51 -


Total production volumes increased to 117.6 Bcfe for the year ended December 31, 2012 from 106.8 Bcfe for the year ended December 31, 2011, primarily due to an 80% increase in oil production for the year ended December 31, 2012. Due to lower natural gas commodity prices in 2012, we discontinued drilling activity in the Piceance Basin and West Tavaputs area in the Uinta Basin to concentrate on our oil development programs. Although our natural gas production increased during the year ended December 31, 2012, we expect natural gas production declines in future periods due to discontinuing our natural gas drilling programs to concentrate on oil drilling programs. In addition, we completed a sale of natural gas assets including 100% of our Wind River Basin and Powder River Basin coalbed methane properties, and an initial 18% interest in the Gibson Gulch assets in the Piceance Basin that progresses to a 26% interest in 2016, as of December 31, 2012. Additional information concerning production is in the following table:

 

    Year Ended December 31, 2012     Year Ended December 31, 2011     % Increase (Decrease)  
    Oil     Natural Gas     Total     Oil     Natural Gas     Total     Oil     Natural Gas     Total  
    (MBbls)     (MMcf)     (MMcfe)     (MBbls)     (MMcf)     (MMcfe)     (MBbls)     (MMcf)     (MMcfe)  

Piceance Basin

    619        48,072        51,786        540        45,606        48,846        15     5     6

Uinta-West Tavaputs

    61        34,497        34,863        54        31,719        32,043        13     9     9

Uinta Oil

    1,479        2,653        11,527        779        1,575        6,249        90     68     84

DJ Basin

    397        1,264        3,646        47        270        552        nm     nm     nm

Powder River-CBM

    0        10,888        10,888        0        13,223        13,223        0     (18 )%      (18 )% 

Powder River Oil

    101        126        732        40        104        344        153     21     113

Wind River Basin

    18        3,913        4,021        22        5,208        5,340        (18 )%      (25 )%      (25 )% 

Other

    12        73        145        8        151        199        50     (52 )%      (27 )% 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

Total

    2,687        101,486        117,608        1,490        97,856        106,796        80     4     10
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

* Not meaningful.

Hedging Activities. In 2012, approximately 76% of our oil volumes, 68% of our natural gas volumes (excluding basis-only swaps, which were equivalent to 7% of our natural gas volumes) and 23% of our NGL-related recoveries were subject to financial hedges, which resulted in an increase in oil revenues of $15.0 million, of which $3.9 million was included in the oil and gas production revenue line item, and an increase in natural gas revenues of $108.5 million, of which $77.2 million was included in the oil and gas production revenue line item, after settlements for all commodity derivatives, including basis-only and NGL swaps. In 2011, approximately 67% of our natural gas volumes (excluding basis-only swaps, which were equivalent to 7% of our natural gas volumes), 53% of our NGL related recoveries and 66% of our oil volumes were subject to financial hedges, which resulted in a decrease in oil revenues of $2.0 million and an increase in natural gas revenues of $73.9 million after settlements for all commodity derivatives, including basis-only and NGL swaps. The increase in oil and natural gas hedge related revenues primarily resulted from lower average oil and natural gas prices during the year ended December 31, 2012 as compared to the year ended December 31, 2011.

Other Operating Revenues. Other operating revenues decreased to a loss of $0.4 million for the year ended December 31, 2012 from $4.9 million for the year ended December 31, 2011. Other operating revenues for 2012 consisted of a $4.5 million loss on the sale of our natural gas assets including 100% of our Wind River Basin and Powder River Basin coalbed methane assets, and a non-operating working interest in our Piceance Basin development property. This loss was offset by $2.7 of income from gathering, compression and salt-water disposal fees received from third parties and $1.4 million from the sale of seismic data. Other operating revenues for 2011 primarily consisted of $2.9 million of income from gathering, compression and salt-water disposal fees received from third parties and $2.0 million in net gains realized from the sale and exchange of properties.

Lease Operating Expense. Lease operating expense increased to $0.62 per Mcfe for the year ended December 31, 2012 from $0.53 per Mcfe for the year ended December 31, 2011. The increase in lease operating expense is primarily related to oil producing properties in the Uinta and DJ Basins with inherently higher lifting

 

- 52 -


costs per Mcfe compared to our natural gas properties. As our development in the Uinta Oil Program continues to grow, we are adding necessary infrastructure and scale to reduce future operating costs on a unit of production basis.

Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.91 per Mcfe for the year ended December 31, 2012 from $0.87 per Mcfe for the year ended December 31, 2011. The increase for the year ended December 31, 2012 is primarily related to decreased drilling activity in the West Tavaputs area of the Uinta Basin due to lower gas prices. As a result of decreased drilling in 2012 and future years, we incurred a one-time charge of $4.4 million for deferred processing and gathering costs that we do not expect to recover in future years.

We have entered into long-term firm transportation agreements for a portion of our natural gas production to guarantee capacity on major pipelines and reduce the risk and impact related to possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation and processing agreements are for gas production in the Piceance and Uinta Basins. Included in gathering, transportation and processing expense are $0.38 and $0.33 per Mcfe of firm transportation and gathering expense for the years ended December 31, 2012 and 2011, respectively, and $0.05 per Mcfe of firm processing expense from long-term contracts for both the years ended December 31, 2012 and 2011. As a result of the sale of 100% of our Powder River Basin coalbed methane assets on December 31, 2012, our long-term firm transportation agreements related to this area were assumed by the purchaser.

Production Tax Expense. Total production taxes decreased to $25.5 million for the year ended December 31, 2012 from $37.5 million for the year ended December 31, 2011. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense decreased during the year ended December 31, 2012 primarily due to a 9.1% decrease in wellhead values of production, excluding hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 4.1% for the year ended December 31, 2012 and 5.5% for the year ended December 31, 2011.

Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The decrease in the overall production tax rate is consistent with our production decrease in states with higher production tax rates.

Exploration Expense. Exploration expense increased to $8.8 million for the year ended December 31, 2012 from $3.6 million for the year ended December 31, 2011. Exploration expense for the year ended December 31, 2012 consisted of $7.9 million for geological and geophysical seismic programs across several basins and $0.9 million for delay rentals across all basins. Exploration expense for the year ended December 31, 2011 consisted of $2.7 million for geological and geophysical seismic programs across several basins and $0.9 million for delay rentals across all basins.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense decreased to $67.9 million for the year ended December 31, 2012 from $117.6 million for the year ended December 31, 2011. For the year ended December 31, 2012, impairment expense was $37.3 million, abandonment expense was $9.6 million and dry hole costs were $21.0 million. For the year ended December 31, 2011, impairment expense was $100.3 million, abandonment expense was $3.9 million and dry hole costs were $13.4 million.

We evaluate the impairment of our proved oil and gas properties on a property-by-property basis annually or whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the property to fair value through a charge to impairment expense. For the year ended December 31, 2012, we did

 

- 53 -


not record any impairment charges regarding proved oil and gas properties. For the year ended December 31, 2011, we recorded a $75.2 million impairment charge regarding proved oil and gas properties within the coalbed methane fields of the Powder River Basin and a $7.6 million impairment charge regarding proved oil and gas properties within the Wallace Creek field of the Wind River Basin as a result of declining natural gas prices.

Unproved oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop existing acreage. We recorded non-cash impairment charges of $37.3 million and $17.5 million for the years ended December 31, 2012 and 2011, respectively, related to certain unproved oil and gas properties within various exploration and development projects primarily as a result of unfavorable natural gas exploratory results, unfavorable market conditions or discontinuing evaluation of the remaining acreage.

We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities. We continue to review our acreage position and future drilling plans based on the current price environment. If our attempts to market interests in certain properties to industry partners are unsuccessful, we may record additional leasehold impairments and abandonments in exploration prospects.

We account for oil and gas exploration and production activities using the successful efforts method of accounting under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well, and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. As of December 31, 2012, there were no exploratory well costs included in unproved oil and gas properties that had been capitalized for a period greater than one year since the completion of drilling.

Dry hole costs of $21.0 million for the year ended December 31, 2012 primarily relate to two unsuccessful exploratory natural gas wells in the Paradox Basin and one unsuccessful exploratory well in the Alberta Basin. Dry hole costs of $13.4 million for the year ended December 31, 2011 were associated with one uneconomic exploratory well in the McRae Gap prospect of the Wind River Basin and two unsuccessful exploratory wells within the northern DJ Basin on acreage acquired prior to our 2011 DJ Basin acquisition.

Depreciation, Depletion and Amortization. DD&A increased to $326.8 million for the year ended December 31, 2012 compared with $288.4 million for the year ended December 31, 2011. The increase of $38.4 million was a result of a 10% increase in production for the year ended December 31, 2012 compared with the year ended December 31, 2011 coupled with an increase in the DD&A rate. The increase in production accounted for $14.4 million of additional DD&A expense, while the overall increase in the DD&A rate accounted for a $24.0 million increase in DD&A expense. The increase in the DD&A rate during the year ended December 31, 2012 was due to an increase in the mix of oil projects, which have higher capital costs compared to natural gas projects, completed during the year ended December 31, 2012 compared to the year ended December 31, 2011.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the year ended December 31, 2012, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $2.91 per Mcfe compared with $2.70 per Mcfe for the year ended December 31, 2011. Future depletion rates will be adjusted to reflect capital expenditures, changes in commodity prices, proved reserve changes and well performance.

 

- 54 -


General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $52.2 million for the year ended December 31, 2012 from $47.7 million for the year ended December 31, 2011. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 51 for a reconciliation and explanation. This increase was primarily due to increased employee compensation and benefits expense, as well as severance costs incurred in 2012. Our Chief Executive Officer and President resigned in January of 2013 and in connection with his resignation we will incur a cash severance expense of $2.0 million that, is payable in eight quarterly installments beginning in June of 2013. On a per Mcfe basis, general and administrative expense, excluding non-cash stock based compensation, decreased to $0.44 in 2012 from $0.45 in 2011, due to the 10% increase in production from 2011 to 2012.

Non-cash stock-based compensation expense was $16.4 million for the year ended December 31, 2012 compared with $19.0 million for the year ended December 31, 2011. Non-cash stock-based compensation expense for 2012 and 2011 related primarily to the vesting of our stock option awards, nonvested shares of common stock, and nonvested performance-based equity granted to employees.

The components of non-cash stock-based compensation expense for 2012 and 2011 are shown in the following table:

 

     Year Ended December 31,  
           2012                2011      
     (in thousands)  

Stock options and nonvested equity shares of common stock

   $ 15,435       $ 18,100   

Shares issued for 401(k) plan

     733         629   

Shares issued for directors’ fees

     276         307   
  

 

 

    

 

 

 

Total

   $ 16,444       $ 19,036   
  

 

 

    

 

 

 

Interest Expense. Interest expense increased to $95.5 million for the year ended December 31, 2012 from $58.6 million for the year ended December 31, 2011. The increase was primarily due to an increase in our weighted average outstanding debt, partially offset by lower average borrowing costs. Our weighted average outstanding debt increased to $1,175.4 million for the year ended December 31, 2012 from $587.4 million for the year ended December 31, 2011, primarily due to the issuance of our $400.0 million aggregate principal amount of 7.0% Senior Notes on March 12, 2012, a $100.8 million lease financing obligation entered into on July 23, 2012, and an increase in the outstanding debt balance on our Amended Credit Facility, partially offset by the repayment of $147.2 million of Convertible Notes on March 20, 2012. Our weighted average interest rate for the year ended December 31, 2012 was 8.2% compared to 10.2% for the year ended December 31, 2011.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. We capitalized interest costs of $0.5 million and $1.4 million for the years ended December 31, 2012 and 2011, respectively. For the year ended December 31, 2012, we had fewer projects in progress as compared with the year ended December 31, 2011, which resulted in a lower amount of interest costs that were capitalized during the period.

Income Tax Expense. Income tax expense totaled $1.6 million and $17.7 million for the years ended December 31, 2012 and 2011, respectively, resulting in effective tax rates of 73.8% and 36.5%, respectively. Our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes. The effective tax rate increase from 2011 to 2012 was primarily the result of the decrease in operating income coupled with an increase in unfavorable book to tax differences affecting the tax rate calculation, mainly the decrease in tax deductible compensation related to incentive stock options. Additionally, a greater proportion of our operating revenue was attributable to higher tax rate jurisdictions, which increased the

 

- 55 -


overall statutory tax rate. The effect of this rate increase on our prior year net deferred tax liability was included in income tax expense for the year ended December 31, 2012. At December 31, 2012, we had approximately $107.9 million of federal tax net operating loss carryforwards, or “NOLs”, which expire through 2032. We also had a federal alternative minimum tax credit carryforward of $1.3 million, which has no expiration date. We believe it is more likely than not that we will use these tax attributes to offset and reduce current tax liabilities in future years. During the year ended December 31, 2012, due to a Colorado limitation on the ability to utilize state NOLs, we released $0.5 million of the previously recorded valuation allowance against state income tax credit carryforwards. The remaining $4.6 million deferred tax asset related to state income tax credit carryforwards continues to have a valuation allowance against it. We believe it is more likely than not that this deferred tax asset will not be realized.

Year Ended December 31, 2011 Compared with Year Ended December 31, 2010

The following table sets forth selected operating data for the periods indicated:

 

     Year Ended
December 31,
    Increase (Decrease)  
   2011     2010     Amount     Percent  
   ($ in thousands, except per unit data)  

Operating Results:

        

Operating and other revenues

        

Oil and gas production

   $ 780,751      $ 708,452      $ 72,299        10

Commodity derivative loss

     (14,263     (10,579     (3,684     (35 )% 

Other

     4,873        591        4,282        nm
  

 

 

   

 

 

   

 

 

   

Total operating and other revenues

   $ 771,361      $ 698,464      $ 72,897        10
  

 

 

   

 

 

   

 

 

   

Operating expenses

        

Lease operating expense

     56,603        52,040        4,563        9

Gathering, transportation and processing expense

     93,423        69,089        24,334        35

Production tax expense

     37,498        32,738        4,760        15

Exploration expense

     3,645        9,121        (5,476     (60 )% 

Impairment, dry hole costs and abandonment expense

     117,599        44,664        72,935        163

Depreciation, depletion and amortization

     288,421        260,665        27,756        11

General and administrative expense (1)

     47,744        40,884        6,860        17

Non-cash stock-based compensation expense (1)

     19,036        16,908        2,128        13
  

 

 

   

 

 

   

 

 

   

Total operating expenses

   $ 663,969      $ 526,109      $ 137,860        21
  

 

 

   

 

 

   

 

 

   

Production Data:

        

Natural gas (MMcf)

     97,856        89,964        7,892        9

Oil (MBbls)

     1,490        1,089        401        37

Combined volumes (MMcfe)

     106,796        96,498        10,298        11

Daily combined volumes (MMcfe/d)

     293        264        29        11

Average Prices (2):

        

Natural gas (per Mcf) (2)

   $ 6.46      $ 6.74      $ (0.28     (4 )% 

Oil (per Bbl)

     80.63        69.91        10.72        15

Combined (per Mcfe)

     7.05        7.07        (0.02     0

Average Costs (per Mcfe):

        

Lease operating expense

   $ 0.53      $ 0.54      $ (0.01     (2 )% 

Gathering, transportation and processing expense

     0.87        0.72        0.15        21

Production tax expense

     0.35        0.34        0.01        3

Depreciation, depletion and amortization

     2.70        2.70        0.00        0

General and administrative expense (3)

     0.45        0.42        0.03        7

 

- 56 -


 

* Not meaningful.
(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Consolidated Statements of Operations for a total of $66.8 million and $57.8 million for the years ended December 31, 2011 and 2010, respectively. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expense. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower non-cash stock-based compensation expense.
(2) Average prices shown in the table are net of the effects of all of our realized commodity hedging transactions. Natural gas average prices include the effect of NGL-related revenue.
(3) Excludes non-cash stock-based compensation expense as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Consolidated Statements of Operations, were $0.63 and $0.60 for the years ended December 31, 2011 and 2010, respectively.

Production Revenues and Volumes. Production revenues increased to $780.8 million for the year ended December 31, 2011 from $708.5 million for the year ended December 31, 2010 due to an 11% increase in production and a 1% decrease in oil and natural gas prices on a per Mcfe basis after the effects of realized cash flow hedges. The effects of realized hedges only include settlements from hedging instruments that were designated as cash flow hedges and exclude those that do not qualify, or were not designated, as cash flow hedges such as basis only and NGL swaps. The settlements from hedging instruments that were not designated as cash flow hedges are included in the line item “Commodity derivative loss” within operating revenues in the Consolidated Statements of Operations. See below for more information related to the Commodity derivative loss line item. The net increase in production added approximately $75.3 million of production revenues, and the decrease in average price reduced production revenues by approximately $3.0 million.

Total production volumes increased to 106.8 Bcfe for the year ended December 31, 2011 from 96.5 Bcfe for the year ended December 31, 2010 due to increased production in the Piceance, Uinta and Powder River Basins and production from the DJ Basin wells we acquired in August 2011. The increased production was partially offset by a decrease in production in the Wind River Basin. Additional information concerning production is in the following table:

 

    Year Ended December 31, 2011     Year Ended December 31, 2010     % Increase (Decrease)  
    Oil     Natural Gas     Total     Oil     Natural Gas     Total     Oil     Natural Gas     Total  
    (MBbls)     (MMcf)     (MMcfe)     (MBbls)     (MMcf)     (MMcfe)     (MBbls)     (MMcf)     (MMcfe)  

Piceance Basin

    540        45,606        48,846        563        44,736        48,114        (4 )%      2     2

Uinta-West Tavaputs

    54        31,719        32,043        34        24,021        24,225        59     32     32

Uinta Oil

    779        1,575        6,249        438        877        3,505        78     80     78

DJ Basin

    47        270        552        0        0        0        nm     nm     nm

Powder River-CBM

    0        13,223        13,223        0        13,386        13,386        0     (1 )%      (1 )% 

Powder River Oil

    40        104        344        22        4        136        82     nm     153

Wind River Basin

    22        5,208        5,340        22        6,770        6,902        0     (23 )%      (23 )% 

Other

    8        151        199        10        170        230        (20 )%      (11 )%      (13 )% 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

Total

    1,490        97,856        106,796        1,089        89,964        96,498        37     9     11
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

* Not meaningful.

The production increase in the Piceance Basin was primarily the result of our initial sales from 119 new gross wells during 2011. The production increase in the Uinta Basin resulted primarily from our development activities in the West Tavaputs area with initial sales from 86 new gross wells during 2011. In addition, we had increased production resulting from our Uinta Oil Program at Blacktail Ridge and Lake Canyon, which had

 

- 57 -


initial sales from 33 new gross wells during 2011, as well as the acquisition of East Bluebell in June 2011, which added 610 MMcfe of additional production. The production increase in the Powder River Basin was due to increased oil production in the Powder River Basin due to initial sales on 20 new gross conventional wells in 2011, offset by natural production declines in our natural gas producing coalbed methane fields with no significant drilling or recompletion activities to offset these declines. Further, the producing wells we acquired within the DJ Basin field in August 2011 added to our production increases during 2011. The production decrease in the Wind River Basin was due to natural production declines with no significant drilling or recompletion activities to offset these declines.

Hedging Activities. In 2011, approximately 67% of our natural gas volumes (excluding basis-only swaps, which were equivalent to 7% of our natural gas volumes), 53% of our NGL-related recoveries and 66% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $73.9 million and a decrease in oil revenues of $2.0 million after settlements for all commodity derivatives, including basis-only and NGL swaps. In 2010, approximately 74% of our natural gas volumes (excluding basis-only swaps, which were equivalent to 12% of our natural gas volumes), 54% of NGL related volumes and 53% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $133.2 million and an increase in oil revenues of $2.2 million after settlements for all commodity derivatives, including basis-only swaps. The decrease in revenues related to hedging natural gas resulted from the expiration of hedges entered into at higher prices and our inability to enter into new hedges at those prices because natural gas prices have fallen since we entered into those hedges.

Commodity Derivative Loss. The “Commodity derivative loss” line item on the Consolidated Statements of Operations is comprised of ineffectiveness on cash flow hedges and realized and unrealized gains and losses on hedges that do not qualify for cash flow hedge accounting or were not designated as cash flow hedges. Ineffectiveness on cash flow hedges relates to slight differences between the contracted location and the actual delivery location. Unrealized gains and losses represent the change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting, which includes our basis only swaps and NGL swaps. As those instruments settle, their settlement will be presented as realized gains and losses within this same line item. In addition to the basis only and NGL swaps, we had certain cash flow hedges that were de-designated in 2011 and settled prior to December 31, 2011. As a result, their settlements were reflected in realized gains and losses for the year ended December 31, 2011.

Commodity derivative loss increased to a loss of $14.3 million for the year ended December 31, 2011 from a loss of $10.6 million for the year ended December 31, 2010 primarily due to the increase in realized losses and the decrease in unrealized gains resulting from the change in fair value of our basis only swaps as of December 31, 2011.

The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative loss for the periods indicated:

 

     Year Ended December 31,  
           2011               2010      
     (in thousands)  

Realized losses on derivatives not designated as cash flow hedges

   $ (28,054   $ (26,166

Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges

     1,026        (2,256

Unrealized gains on derivatives not designated as cash flow hedges

     12,765        17,843   
  

 

 

   

 

 

 

Total commodity derivative loss

   $ (14,263   $ (10,579
  

 

 

   

 

 

 

Other Operating Revenues. Other operating revenues increased to $4.9 million for the year ended December 31, 2011 from $0.6 million for the year ended December 31, 2010. Other operating revenues for 2011 primarily consisted of $2.9 million of income from gathering, compression and salt-water disposal fees received

 

- 58 -


from third parties and $2.0 million in net gains realized from the sale and exchange of properties. Other operating revenues for 2010 consisted of $2.6 million of income from gathering, compression and salt-water disposal fees received from third parties offset by $2.0 million in net losses realized from the sale and exchange of properties.

Lease Operating Expense. Lease operating expense decreased to $0.53 per Mcfe for the year ended December 31, 2011 from $0.54 per Mcfe for the year ended December 31, 2010. The year ended December 31, 2010 included $2.4 million of nonrecurring remediation efforts related to a condensate leak at the Dry Canyon Compressor Station in the Uinta Basin, which increased lease operating expense by $0.02 per Mcfe. The drilling program in our Blacktail Ridge field in the Uinta Basin throughout 2011 increased water production. The additional trucking and disposal costs associated with this water production were primarily responsible for the overall increase in lease operating expense.

Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.87 per Mcfe for the year ended December 31, 2011 from $0.72 per Mcfe for the year ended December 31, 2010. Increased production from the West Tavaputs field within the Uinta Basin led to an increase in volumes gathered, transported and processed under higher cost structured agreements that resulted in higher costs on a per unit basis. As a result, gathering, transportation and processing expense increased approximately $0.10 per Mcfe for the year ended December 31, 2011 compared to the year ended December 31, 2010. Firm transportation agreements related to West Tavaputs that became effective in late July 2011 for the Ruby Pipeline and Wyoming Interstate Company Pipeline were the primary reason for this increase. The remaining increase in gathering, transportation and processing expense on a per unit basis related to new gathering and transportation agreements in the Blacktail Ridge field and the Piceance Basin, which added approximately $0.02 per Mcfe for each area. In 2011, we incurred one-time charges of $0.01 per Mcfe related to gathering and processing agreements in the Paradox and Powder River Basins.

We have entered into long-term firm transportation contracts for a portion of our production to guarantee capacity on major pipelines and reduce the risk and impact related to possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production in the Piceance and Uinta Basins. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Piceance and Uinta Basins. Included in gathering, transportation and processing expense are $0.33 and $0.19 per Mcfe of firm transportation and gathering expense for the years ended December 31, 2011 and 2010, respectively, and $0.05 and $0.04 per Mcfe of firm processing expense from long-term contracts for the years ended December 31, 2011 and 2010 respectively. The increase in firm transportation and gathering expense to $0.33 per Mcfe for the year ended December 31, 2011 compared with $0.18 per Mcfe for the year ended December 31, 2010 was the result of additional long-term contracts executed with various pipelines for our natural gas production in the Piceance and Uinta Basins as mentioned above.

Production Tax Expense. Total production taxes increased to $37.5 million for the year ended December 31, 2011 from $32.7 million for the year ended December 31, 2010. The increase in production taxes is primarily related to an increase in production revenues during the year ended December 31, 2011. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense for the year ended December 31, 2010 included a one-time reduction of $2.2 million related to amended 2004 through 2009 State of Utah annual severance tax calculations. Production taxes as a percentage of natural gas and oil sales before hedging adjustments was 5.5% for the year ended December 31, 2011 compared with 6.0% for the year ended December 31, 2010, which included a reduction of 0.4% related to the nonrecurring item associated with Utah severance taxes.

Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The decrease in the overall production tax rate is consistent with our production increase throughout 2011 from states with lower production tax rates.

 

- 59 -


Exploration Expense. Exploration expense decreased to $3.6 million for the year ended December 31, 2011 from $9.1 million for the year ended December 31, 2010. Exploration expense for the year ended December 31, 2011 consisted of $2.7 million for geological and geophysical seismic programs across several basins and $0.9 million for delay rentals across all basins. Exploration expense for the year ended December 31, 2010 consisted of $3.5 million for seismic programs, $1.1 million for delay rentals, $0.1 million related to the evaluation of non-acquired assets and $4.4 million for one scientific well drilled for data gathering purposes.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $117.6 million for the year ended December 31, 2011 from $44.7 million for the year ended December 31, 2010. For the year ended December 31, 2011, impairment expense was $100.3 million, abandonment expense was $3.9 million and dry hole costs were $13.4 million. For the year ended December 31, 2010, impairment expense was $15.6 million, abandonment expense was $2.6 million and dry hole costs were $26.5 million.

We evaluate the impairment of our proved oil and gas properties on a property-by-property basis whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the property to fair value through a charge to impairment expense. As a result of declining natural gas prices, we recorded a $75.2 million impairment charge regarding proved oil and gas properties within the coalbed methane fields of the Powder River Basin and a $7.6 million impairment charge regarding proved oil and gas properties within the Wallace Creek field of the Wind River Basin for the year ended December 31, 2011. For the year ended December 31, 2010, we did not record any impairment charges on proved oil and gas properties.

Unproved oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop existing acreage. During the year ended December 31, 2011, we recorded a $17.5 million impairment charge regarding unproved oil and gas properties within various exploration projects. This non-cash impairment charge was primarily a result of unfavorable market conditions as well as uneconomic drilling results in exploratory areas where we currently have no plans to develop or evaluate the remaining acreage. For the year ended December 31, 2010, we recorded a $15.6 million impairment charge regarding unproved oil and gas properties within various exploration projects.

We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities. We continue to review our acreage position and future drilling plans based on the current price environment. If our attempts to market interests in certain properties to industry partners are unsuccessful, additional leasehold impairments and abandonments in exploration prospects may be recorded.

Dry hole costs of $13.4 million for the year ended December 31, 2011 were associated with one uneconomic exploratory well in the McRae Gap prospect of the Wind River Basin and two unsuccessful exploratory wells within the northern DJ Basin on acreage acquired prior to our 2011 DJ Basin acquisition. Dry hole costs of $26.5 million for the year ended December 31, 2010 were associated with seven unsuccessful exploratory wells within the Paradox Basin and one unsuccessful exploratory well in each of the Uinta and Big Horn Basins.

Depreciation, Depletion and Amortization. DD&A was $288.4 million for the year ended December 31, 2011 compared with $260.7 million for the year ended December 31, 2010. The increase of $27.7 million was a result of increased production during the year ended December 31, 2011 compared with the year ended December 31, 2010. The weighted average DD&A rate for each of the years ended December 31, 2011 and 2010 was $2.70 per Mcfe. Under successful efforts accounting, DD&A expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average DD&A rate for current production. Future DD&A rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

 

- 60 -


General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $47.7 million for the year ended December 31, 2011 from $40.9 million for the year ended December 31, 2010. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 57 for a reconciliation and explanation. This increase was primarily due to a 12% increase in headcount in 2011, which increased employee compensation and benefits. On a per Mcfe basis, general and administrative expense, excluding non-cash stock based compensation, increased to $0.45 in 2011 from $0.42 in 2010.

Non-cash stock-based compensation expense was $19.0 million for the year ended December 31, 2011 compared with $16.9 million for the year ended December 31, 2010. Non-cash stock-based compensation expense for 2011 and 2010 related primarily to the vesting of our stock option awards and nonvested shares of common stock granted to employees.

The components of non-cash stock-based compensation expense for 2011 and 2010 are shown in the following table:

 

     Year Ended December 31,  
         2011              2010      
     (in thousands)  

Stock options and nonvested equity shares of common stock

   $ 18,100       $ 16,016   

Shares issued for 401(k) plan

     629         579   

Shares issued for directors’ fees

     307         313   
  

 

 

    

 

 

 

Total

   $ 19,036       $ 16,908   
  

 

 

    

 

 

 

Interest Expense. Interest expense increased to $58.6 million for the year ended December 31, 2011 from $44.3 million for the year ended December 31, 2010. The increase was primarily due to an increase in our weighted average outstanding debt, including our Amended Credit Facility, Convertible Notes, 9.875% Senior Notes and 7.625% Senior Notes, to $587.4 million for the year ended December 31, 2011 from $403.4 million for the year ended December 31, 2010. The increase in our weighted average outstanding debt was primarily due to the issuance of our $400.0 million aggregate principal amount of 7.625% Senior Notes on September 27, 2011 and an increase in the outstanding debt balance on our Amended Credit Facility during the year ended December 31, 2011. However, our effective interest rate decreased to 10.2% for the year ended December 31, 2011 compared with 12.1% for the year ended December 31, 2010.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. We capitalized interest costs of $1.4 million and $4.2 million for the years ended December 31, 2011 and 2010, respectively. For the year ended December 31, 2011, we had fewer projects in progress as compared with the year ended December 31, 2010, which resulted in a lower amount of interest costs that were capitalized during the period.

Income Tax Expense. Income tax expense totaled $17.7 million and $48.0 million for the years ended December 31, 2011 and 2010, resulting in effective tax rates of 36.5% and 37.3% in 2011 and 2010, respectively. Our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes. The effective tax rate decrease from 2010 to 2011 was primarily the result of a net reduction in permanent differences affecting the tax rate calculation, principally the increase in tax deductible compensation related to incentive stock options. Additionally, a greater proportion of our operating revenue was attributable to lower tax rate jurisdictions, thereby decreasing the overall statutory tax rate. The effect of this rate decrease on our prior year net deferred tax liability was included in income tax expense for 2011. At December 31, 2011, we had approximately $125.3 million of NOLS which expire through 2031. We also had a federal alternative minimum tax credit carryforward of $0.1 million, which has no expiration date. We believe it

 

- 61 -


is more likely than not that we will use these tax attributes to offset and reduce current tax liabilities in future years. During 2011, we recorded a valuation allowance of $4.2 million against a deferred tax asset of the same amount for state income tax credit carryforwards. The valuation allowance has no impact on our income tax expense, as the credits were not recorded as deferred tax assets in prior years. We believe it is more likely than not that this deferred tax asset will not be realized.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, including our Convertible Notes and senior notes, bank credit facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital. In addition, our hedge positions currently provide relative certainty on a majority of our cash flows from operations through 2013 even with the general decline in the price of natural gas. See, “ – Trends and Uncertainties – Declining Commodity Prices” below. We have committed not to increase our total indebtedness at December 31, 2013 compared to December 31, 2012. As a result expenditures in excess of cash flow and any acquisitions in 2013 would require us to sell other properties.

At December 31, 2012, we had cash and cash equivalents of $79.4 million and a zero balance outstanding under our Amended Credit Facility. As of December 31, 2012, the commitments on our Amended Credit Facility decreased from $900.0 million to $825.0 million as a result of the sale of certain of our non-core natural gas assets including our Wind River Basin natural gas producing properties and the Powder River Basin coalbed methane assets, and a non-operating working interest in our Piceance Basin development property. Our borrowing capacity is further reduced by $26.0 million to $799.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement.

Cash Flow from Operating Activities

Net cash provided by operating activities was $388.4 million, $479.3 million, and $447.2 million in 2012, 2011 and 2010, respectively. The changes in net cash provided by operating activities are discussed above in “— Results of Operations”.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosure about Market Risk” below.

To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap and cashless collar contracts (purchased put options and written call options) to receive fixed prices for a portion of our production revenue. The cashless collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production revenue. We typically hedge a fixed price for natural gas at our sales points (NYMEX less basis) to mitigate the risk of

 

- 62 -


differentials to the NYMEX Henry Hub Index. In addition to the swaps and collars, we also have entered into basis only swaps. With a basis only swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. Although we believe this is an appropriate part of a mitigation strategy, the basis only swaps do not qualify for hedge accounting because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings. All of our basis only swaps and cashless collars were settled as of December 31, 2012. At December 31, 2012, we had in place crude oil financial swaps covering portions of our 2013, 2014 and 2015 production, natural gas financial swaps covering portions of our 2013 and 2014 production and NGL financial swaps covering portions of our 2013 production.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. Before discontinuing hedge accounting effective January 1, 2012, changes in fair value of our derivative instruments that qualified and were designated as cash flow hedges, to the extent the hedges were effective, were recognized in AOCI until the forecasted transaction occurred. The ineffective portion of hedge derivatives was reported in commodity derivative gain (loss) in the Consolidated Statements of Operations. Realized gains and losses on cash flow hedges were transferred from AOCI and recognized in earnings and included within oil and gas production revenues in the Consolidated Statements of Operations as the associated production occurred.

We have also entered into swap contracts to hedge a portion of the amount received related to NGLs resulting from the processing of our gas. Our NGL hedges were not designated as cash flow hedges, and the fair value of these derivative instruments is recorded in earnings in the Consolidated Statements of Operations.

At December 31, 2012, the estimated fair value of all of our commodity derivative instruments was a net asset of $32.6 million, comprised of current and noncurrent assets and noncurrent liabilities. We will reclassify the appropriate cash flow hedge amounts from AOCI, related to hedges designated as cash flow hedges prior to January 1, 2012, to gains and losses included in oil and gas production revenues as the hedged production quantities are produced. As a result of our election to discontinue cash flow hedge accounting effective January 1, 2012, we did not have any derivatives designated as cash flow hedging instruments at December 31, 2012. We estimate that the net amount of existing unrealized after-tax income relating to cash flow hedges as of December 31, 2012 to be reclassified from AOCI to earnings in the year ended December 31, 2013 would be a gain of approximately $4.7 million. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. We anticipate that all originally forecasted transactions related to our derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods. For a more detailed discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” — Overview” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

The hedge instruments designated as cash flow hedges prior to January 1, 2012 were at liquid trading locations but contained slight differences compared to the delivery location of the forecasted sale, which resulted in ineffectiveness. Ineffectiveness related to our cash flow derivative instruments resulted in unrealized losses of $1.0 million and $2.3 million for the years ended December 31, 2011 and 2010, respectively, which was reported in commodity derivative loss in the Consolidated Statements of Operations. Because we de-designated all derivative hedges as of January 1, 2012, we did not recognize any ineffectiveness for the year ended December 31, 2012.

 

- 63 -


The table below summarizes the realized and unrealized gains and losses that we recognized related to our oil and natural gas derivative instruments for the periods indicated:

 

     Year Ended December 31,  
     2012      2011     2010  
     (in thousands)  

Realized gains on derivatives designated as cash flow hedges (1)

   $ 81,166       $ 99,922      $ 161,496   
  

 

 

    

 

 

   

 

 

 

Realized gains (losses) on derivatives not designated as cash flow hedges

     42,305         (28,054     (26,166

Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges

     0         1,026        (2,256

Unrealized gains on derivatives not designated as cash flow hedges

     30,454         12,765        17,843   
  

 

 

    

 

 

   

 

 

 

Total commodity derivative gain (loss) (2)

   $ 72,759       $ (14,263   $ (10,579
  

 

 

    

 

 

   

 

 

 

 

(1) Included in “Oil and gas production” revenues in the Consolidated Statements of Operations.
(2) Included in “Commodity derivative gain (loss)” in the Consolidated Statements of Operations.

The following table summarizes all of our hedges in place as of December 31, 2012:

 

Contract

   Total
Hedged
Volume
     Quantity
Type
   Weighted
Average
Fixed
Price
     Index
Price(1)
   Fair
Value
 

Swap Contracts:

              

2013

              

Natural gas

     1,375,000       MMBtu    $ 5.51       CIG    $ 2,938   

Natural gas

     49,100,000       MMBtu    $ 3.65       NWPL      13,108   

Natural gas liquids(2)

     13,500,000       Gallons    $ 1.78       Mt. Belvieu      1,771   

Oil

     2,555,000       Bbls    $ 98.00       WTI      12,164   

2014

              

Natural gas

     27,375,000       MMBtu    $ 3.83       NWPL      (2,018

Oil

     985,500       Bbls    $ 96.77       WTI      4,498   

2015

              

Oil

     182,500       Bbls    $ 90.56       WTI      96   
              

 

 

 

Total

               $ 32,557   
              

 

 

 

The following table includes all hedges entered into subsequent to December 31, 2012 through January 25, 2013:

 

Contract

   Total
Hedged
Volumes
     Quantity
Type
     Weighted
Average
Fixed
Price
     Index
Price(1)
 

Swap Contracts:

           

2014

           

Oil

     185,600         Bbls       $ 92.96         WTI   

 

(1) CIG refers to Colorado Interstate Gas Rocky Mountains and NWPL refers to Northwest Pipeline Corporation price as quoted in Platt’s Inside FERC on the first business day of each month. Mt. Belvieu refers to the average daily price as quoted by Oil Price Information Service (“OPIS”) for Mont Belvieu spot gas liquid prices. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.
(2) Weighted average fixed price includes propane, normal butane, isobutane and natural gasoline hedges.

 

- 64 -


By removing the price volatility from a portion of our oil, natural gas and NGL related revenue for 2013, 2014 and 2015, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

Effective January 1, 2012, we elected to discontinue hedge accounting prospectively. Consequently, as of January 1, 2012, we no longer designate any hedges as cash flow hedges and we de-designated all commodity hedge instruments that were previously designated as cash flow hedges. The election to de-designate our commodity hedges did not impact our reported cash flows, did not affect the economic substance of these transactions and changed only how these transactions are accounted for in our consolidated financial statements. We expect to reclassify $4.7 million of the net after-tax derivative loss from AOCI to earnings during the year ended December 31, 2013.

By using derivative instruments that are not traded or settled on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. Derivative financial instruments that hedge the price of oil and gas are generally executed with major financial or commodities trading institutions that expose us to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. It is our policy to enter into derivative contracts with counterparties that are lenders under our Amended Credit Facility, affiliates of lenders in our Amended Credit Facility or potential lenders in our Amended Credit Facility. Two counterparties that were lenders in the Amended Credit Facility withdrew from the facility when we amended the facility in October 2011. We will continue to monitor the creditworthiness of these two counterparties during the remaining duration of the derivatives that were entered into while they were lenders in the Amended Credit Facility. Furthermore, where the counterparty is a lender, in the event of an insolvency of such counterparty our hedging agreements and applicable law permit us to set-off amounts we owe under the Amended Credit Facility against amounts owed to us by such counterparty under such hedging agreements. Where the counterparty is not a lender and the counterparty’s obligations are not guaranteed by a lender, such set off may not be possible even where the relevant agreement provides for it.

Capital Expenditures

Our capital expenditures are summarized in the following tables:

 

     Year Ended December 31,  
     (in millions)  
      2012      2011      2010  

Basin/Area

        

Piceance

   $ 207.7       $ 209.2       $ 269.8   

Uinta – West Tavaputs

     106.5         269.1         85.9   

Uinta Oil

     314.5         250.5         56.7   

DJ

     226.2         181.7         11.8   

Powder River—CBM

     0.0         4.1         11.4   

Powder River Oil

     47.4         47.2         12.9   

Wind River

     0.2         4.4         8.3   

Paradox

     18.3         2.5         7.1   

Other

     41.8         18.6         9.4   
  

 

 

    

 

 

    

 

 

 

Total including acquisitions

   $ 962.6       $ 987.3       $ 473.3   

 

- 65 -


     Year Ended December 31,  
     (in millions)  
     2012      2011      2010  

Acquisitions of proved and unproved properties and other real estate

   $ 168.5       $ 350.2       $ 30.1   

Drilling, development, exploration and exploitation of natural gas and oil properties(1)

     778.4         624.6         432.0   

Geologic and geophysical costs

     8.8         3.6         9.1   

Furniture, fixtures and equipment

     6.9         8.9         2.1   
  

 

 

    

 

 

    

 

 

 

Total(2)(3)

   $ 962.6       $ 987.3       $ 473.3   
  

 

 

    

 

 

    

 

 

 

 

(1) Includes related gathering and facilities costs.
(2) For the years ended December 31, 2012, 2011 and 2010, we received $325.3 million, $2.0 million and $2.9 million respectively, of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.
(3) Excludes future reclamation liability accruals of $7.5 million, $12.1 million and $1.3 million for the years ended December 31, 2012, 2011 and 2010, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $39.3 million, $21.0 million and $38.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Capital expenditures for acquisitions of proved and unproved properties and other real estate were $168.5 million for the year ended December 31, 2012. This was primarily related to our acquisitions of proved and unproved properties in the DJ, Powder River and Uinta Basins. The increase in drilling, development, exploration and exploitation of oil and natural gas properties to $778.4 million from $624.6 million for the year ended December 31, 2011 is related to an increase in development drilling and completion activities within the Uinta, Powder River and DJ Basins.

Capital expenditures for acquisitions of proved and unproved properties and other real estate were $350.2 million for the year ended December 31, 2011. This was primarily related to our acquisitions of proved and unproved properties in the DJ, Powder River and Uinta Basins. The increase in drilling, development, exploration and exploitation of oil and natural gas properties to $624.6 million from $432.0 million for the year ended December 31, 2010 is related to an increase in development drilling and completion activities within the Piceance, Uinta, Powder River and DJ Basins.

Our current estimated capital expenditure budget in 2013 is $475.0 million to $525.0 million, with all drilling activities targeting oil. The budget includes facilities costs and excludes acquisitions. We may adjust capital expenditures throughout the year as business conditions and operating results warrant. If we are successful in exploratory activities or overcoming legal and regulatory hurdles, we may consider increasing our capital budget. We believe that we have sufficient available liquidity through 2013 with available cash under the Amended Credit Facility, our hedge positions and cash flow from operations to fund our budgeted capital expenditures. Future cash flows are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures. We have committed not to increase our total indebtedness at December 31, 2013 compared to December 31, 2012. As a result, expenditures in excess of cash flow and any acquisitions in 2013 would require us to sell other properties.

The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil and natural gas prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity generally by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow. We routinely monitor and adjust our capital expenditures, including acquisitions and divestitures, in

 

- 66 -


response to changes in prices and other economic and market conditions, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside of our control.

Financing Activities

Amended Credit Facility. On October 18, 2011, we amended the Amended Credit Facility to extend the maturity date to October 31, 2016. The amended interest margin is LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee ranges from 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility were 2.2% and 2.5% for the years ended December 31, 2012 and December 31, 2011, respectively. As of December 31, 2012, the Company did not have a balance outstanding under the Amended Credit Facility.

The borrowing base is required to be re-determined twice per year. The borrowing base was re-determined on October 1, 2012, with a borrowing base of $900.0 million and commitments of $900.0 million based on June 30, 2012 proved reserves, hedge position, senior debt outstanding and lender commodity price benchmarks. Our borrowing base was re-determined again as of December 31, 2012, with a reduction to the borrowing base to $825.0 million and commitments of $825.0 million as a result of the sale of certain of our non-core natural gas assets including all our Wind River Basin natural gas producing properties and the Powder River Basin coalbed methane assets, and a non-operating working interest in our Gibson Gulch-Piceance Basin development property. Future borrowing bases will be computed based on proved oil and natural gas reserves, hedge position and estimated future cash flows from those reserves, as well as any other outstanding debt. The Amended Credit Facility is secured by oil and natural gas properties representing at least 80% of the value of the our proved reserves and the pledge of all of the stock of our subsidiaries. The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants for all prior periods. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility, effective May 4, 2010, which further reduced the current borrowing capacity of the Amended Credit Facility by $26.0 million to $799.0 million.

Convertible Notes. On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. As of January 1, 2009 with the adoption of new authoritative accounting guidance under FASB ASC subtopic 470-20, Debt with Conversion Options, we recorded a debt discount of $23.1 million, which represented the fair value of the equity conversion feature as of the date of the issuance of the Convertible Notes. The value of the equity conversion feature was also recorded as APIC, net of $8.6 million of deferred taxes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to us and were redeemed by us at par. We settled the notes in cash and recognized a gain on extinguishment of $1.6 million after completing a fair value analysis of the cash consideration transferred to holders of the Convertible Notes compared to the fair value of the Convertible Notes that were redeemed. After the redemption, $25.3 million aggregate principal amount of the Convertible Notes was outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by us. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior unsecured indebtedness, are senior in right of payment to all of our future subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of our subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the 9.875% Senior Notes, the 7.625% Senior Notes and the 7.0% Senior Notes.

The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require us to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2015, March 20, 2018 and

 

- 67 -


March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. We have the right with at least 30 days’ notice to call the Convertible Notes.

For the remainder of the Convertible Notes outstanding, the conversion price is approximately $66.33 per share of our common stock, equal to the applicable conversion rate of 15.0761 shares of common stock, subject to adjustment, for each $1,000 of the principal amount of the Convertible Notes. Upon conversion of the Convertible Notes, holders will receive, at our election, cash, shares of common stock or a combination of cash and shares of common stock. If the conversion value exceeds $1,000, we will also deliver, at our election, cash, shares of common stock or a combination of cash and shares of common stock with respect to the remaining value deliverable upon conversion.

9.875% Senior Notes. The 9.875% Senior Notes have an aggregate principal amount of $250.0 million, are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness. The 9.875% Senior Notes will mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15 of each year. The 9.875% Senior Notes are callable by us on July 15, 2013 at 104.938% of the par value of the notes. The 9.875% Senior Notes are fully and unconditionally guaranteed by our subsidiaries. The 9.875% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens, sell assets and prohibits us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.

7.625% Senior Notes. The 7.625% Senior Notes have an aggregate principal amount of $400.0 million, are our senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness. The 7.625% Senior Notes will mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 of each year. The 7.625% Senior Notes are callable by us on October 1, 2015 at 103.813% of the par value of the notes. The 7.625% Senior Notes are fully and unconditionally guaranteed by our subsidiaries. The 7.625% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens, sell assets and prohibits us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.

7.0% Senior Notes. On March 12, 2012, we issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes will mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. We received net proceeds of $392.0 million (net of related offering costs), which were used to repay the outstanding balance under the Amended Credit Facility, settle the Convertible Notes that were redeemed by us and for general corporate purposes. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness. The 7.0% Senior Notes are callable by us on October 15, 2017 at 103.5% of the par value of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the Convertible Notes, the 9.875% Senior Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. We are currently in compliance with all financial covenants and have complied with all financial covenants for all prior periods.

Lease Financing Obligation. On July 23, 2012, we entered into a lease financing arrangement (the “Lease Financing Obligation”) with Bank of America Leasing & Capital, LLC under which we received $100.8 million through the sale and subsequent leaseback of existing compressors and related facilities owned by us in the West Tavaputs and Gibson Gulch areas. The lease financing arrangement expires on August 10, 2020, and we have the option to purchase the equipment at the end of the lease term for fair market value. The lease financing arrangement also contains an early buyout option where we may purchase the equipment for $36.6 million on

 

- 68 -


February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit rate of 3.3%. As of December 31, 2012, we had a balance of $97.6 million outstanding under the Lease Financing Obligation.

Our outstanding debt is summarized below (in thousands):

 

          As of December 31, 2012     As of December 31, 2011  
    Maturity Date     Principal     Unamortized
Discount
    Carrying
Amount
    Principal     Unamortized
Discount
    Carrying
Amount
 

Amended Credit Facility(1)

    October 31, 2016      $ 0      $ 0      $ 0      $ 70,000      $ 0      $ 70,000   

9.875% Senior Notes(2)

    July 15, 2016        250,000        (7,209     242,791        250,000        (8,802     241,198   

Convertible Notes(3)

    March 15, 2028 (4)      25,344        0        25,344 (5)      172,500        (1,458     171,042   

7.625% Senior Notes(6)

    October 1, 2019        400,000        0        400,000        400,000        0        400,000   

7.0% Senior Notes(7)

    October 15, 2022        400,000        0        400,000        0        0        0   

Lease Financing Obligation(8)

    August 10, 2020        97,596        0        97,596        0        0        0