10-K 1 bbg-12312013x10xk.htm 10-K BBG-12.31.2013-10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
FORM 10-K

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

For the fiscal year ended December 31, 2013
or
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
 
to
 

Commission file number 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.
þ  Yes   ¨  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   þ  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.  þ  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). þ  Yes    ¨  No

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
þ
  
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 Exchange Act).
¨  Yes   þ  No

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 28, 2013 based on the $20.22 closing price of the registrant's common stock on the New York Stock Exchange was $978,357,338.
__________
*
Calculated based on beneficial ownership of our common stock on January 24, 2014. 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 24, 2014, the registrant had 49,154,348 outstanding shares of $0.001 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 2014 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant’s fiscal year ended December 31, 2013.




GLOSSARY OF OIL, NATURAL GAS AND NGL 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.
Boe. Barrel of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.
Boe/d. Boe per day.
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.
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.
EHS. Environmental Health and Safety.

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Environmental Assessment or EA. A study that can be required prior to drilling a federal well.
Environmental Impact Statement or EIS. A more detailed study of the potential direct, indirect and cumulative impacts of a federal 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.
Henry Hub. The Erath, LA settlement point price as quoted in Platt’s Gas Daily on the first flow day of each month.
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.
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.
Mt. Belvieu. The average daily price as quoted by Oil Price Information Service for Mont Belvieu spot gas liquid prices.
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.
NWPL. Northwest Pipeline Corporation price as quoted in Platt’s Inside FERC on the first business day of each month.
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.
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.

3


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 U.S. 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.
SEC. U.S. Securities and Exchange Commission.
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 hydraulic fracturing.
Standardized Measure. The present value of estimated future cash inflows from proved oil, natural gas and NGL 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 oil and natural gas 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.

WTI. West Texas Intermediate price as quoted on the New York Mercantile Exchange.

WTI Cushing. The West Texas Intermediate price at the Cushing, OK settlement point as quoted by Bloomberg, using crude oil price bulletins for the first day of each month.


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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 oil, natural gas and NGLs;
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. 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.




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”) is an independent energy company that develops, acquires and explores for oil and natural gas resources. All of our assets and operations are located in the Rocky Mountain region of the United States.
We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize our operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices and from the settlement of commodity hedges. Due to current and expected commodity prices for oil, natural gas and NGLs, we are focused on developing oil assets where we have established a long-term inventory of drilling locations. As a result, 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 are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with environmental, wildlife and community organizations to ensure that exploration and development activities are designed with all stakeholders in mind.
We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed an initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. Our common stock is traded on the New York Stock Exchange under the symbol “BBG”. The principal executive offices are located at 1099 18th Street, Suite 2300, Denver, Colorado 80202, and the telephone number at that address is (303) 293-9100.

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 and EHS 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.
We operate in one industry segment, which is the exploration, development and production of oil and natural gas, and all 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.

The following table provides summary information by basin as of December 31, 2013:


6


Basin/Area
 
State
 
Estimated Net
Proved Reserves
(MMBoe) (1)
 
December 2013 Average Daily Net Production
(Boe/d) (2)
 
Net Producing Wells (3)
 
Net Undeveloped Acreage
 
Piceance
 
CO
 
72.6

 
14,894

 
745.0

 
41,011

(4) 
Uinta Oil Program
 
UT
 
53.2

 
6,740

 
170.2

 
70,795

(5) 
Denver-Julesburg
 
CO/WY
 
65.8

 
6,066

 
203.3

 
60,672

 
Powder River Oil
 
WY
 
5.4

 
1,543

 
18.1

 
57,806

 
Other
 
Various
 

 
25

 
5.5

 
479,473

 
Total
 
 
 
197.0

 
29,268

 
1,142.1

 
709,757

(4)(5) 

(1)
Our proved reserves were determined in accordance with SEC guidelines, using the average price on the first of each month for natural gas (Henry Hub price) and oil (WTI Cushing price), which averaged $3.67 per MMBtu of natural gas and $96.91 per barrel of oil in 2013, respectively, without giving effect to hedging transactions. The average NGL price of $39.75 per barrel was based on a percentage of the SEC oil price per barrel based on historical price data. 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)
Excludes average daily net production for our West Tavaputs area in the Uinta Basin, which was sold in December 2013.
(3)
Net wells are the sum of our fractional working interests owned in gross wells.
(4)
Includes 36,281 net undeveloped acres associated with our Cottonwood Gulch prospect.
(5)
Excludes an additional 67,500 net undeveloped acres that are subject to drill-to-earn agreements.

Areas of Operation


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. As of December 31, 2013, we had three key areas of production: The Denver-Julesburg Basin (“DJ Basin”), the Uinta Oil Program in the Uinta Basin, and the Gibson Gulch area in the Piceance Basin. We also operate an early stage oil program in Powder River Basin and hold acreage in a number of exploration areas. Among these assets, we actively invested in the DJ Basin, the Uinta Oil Program and the Powder River Oil Program during 2013, all of which target oil resources.

The following table represents the percentage change in the mix of oil, natural gas and NGLs for both production and reserves:

7


 
Year Ended December 31,
 
2013
 
2012
 
2011
 
Oil (1)
 
Natural Gas
 
Oil
 
Natural Gas (2)
 
Oil
 
Natural Gas (2)
Production
39
%
 
61
%
 
14
%
 
86
%
 
8
%
 
92
%
Proved reserves
61
%
 
39
%
 
29
%
 
71
%
 
13
%
 
87
%

(1)
Oil production and proved reserves for 2013 include NGLs.
(2)
For periods prior to January 1, 2013, we presented our production and reserve data for oil and natural gas, which combined NGLs with the natural gas stream, and did not separately report NGLs. This change impacts the comparability of 2013 with prior periods.

Denver-Julesburg Basin

The Company’s acreage positions in the DJ Basin are predominantly located in Colorado’s eastern plains and parts of southeastern Wyoming.

Key Statistics
Estimated proved reserves as of December 31, 2013 - 65.8 MMBoe.
Producing wells - We had interests in 324 gross (203.3 net) producing wells as of December 31, 2013, and we serve as operator in 209 gross wells.
2013 net production - 1,288 MBoe.
Acreage - We held 60,672 net undeveloped acres as of December 31, 2013.
Capital expenditures - Our capital expenditures for 2013 were $209.3 million for participation in the drilling of 78 gross wells, acquire leasehold acres and to construct gathering facilities.
As of December 31, 2013, we were drilling 2 gross wells (0.9 net), and we were waiting to complete 16 gross (12.8 net) wells within the DJ Basin.
As of December 31, 2013, we had a 55% weighted average working interest in producing wells in the DJ Basin.
Our DJ Basin acreage was acquired predominantly through two acquisitions completed in August 2011 and July 2012. The DJ Basin is a high growth oil development area where operators are targeting the Niobrara and Codell formations, and employing new technologies to optimize oil recoveries and economic returns. We believe that the DJ Basin offers us significant growth opportunity through further delineating our current position, potential down-spacing, planned testing of extended reach horizontal wells and further cost optimizations.
The DJ Basin is a core area of operation where we drilled 61 operated wells and completed 44 operated wells in 2013 and had four rigs operating at the end of 2013. In 2013, we focused on delineating the majority of our position in the Northeast Wattenberg area of the DJ Basin, optimizing our completion technology and establishing a scalable development program. In 2013, we drilled 51 operated wells in this area, which was largely undrilled, thereby delineating an estimated 70% of that net 40,000 acre position. In 2013, we also drilled 10 operated wells in the core Wattenberg portion of our position, which is largely de-risked as a result of existing production from vertical wells in the field.

The 2014 drilling program will be predominantly pad drilling, employ an average of three rigs for approximately 85 gross/60 net operated wells plus approximately 45 non-operated wells. The 2014 drilling program includes a combination of standard length and extended reach (9,000 foot) laterals, and downspacing to 40-acres. This program may be modified throughout 2014 as business conditions and operating results warrant.

Our oil production is sold at the lease and trucked to markets. Our gas production is gathered and processed by various third parties and we receive residue gas and NGL revenue under percentage of proceeds contracts.

Uinta Basin
The Uinta Basin is located in northeastern Utah. During 2013, our development operations were conducted through two key programs: our Uinta Oil Program and the West Tavaputs area, which is primarily a natural gas development. The West Tavaputs assets were sold in December 2013 and, therefore, are not included in the key statistics below.

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Uinta Oil Program
Key Statistics
Estimated proved reserves as of December 31, 2013 - 53.2 MMBoe.
Producing wells - We had interests in 299 gross (170.2 net) producing wells as of December 31, 2013, and we serve as operator in 216 gross wells.
2013 net production - 2,642 MBoe.
Acreage - We held 70,795 net undeveloped acres as of December 31, 2013, along with 67,500 net undeveloped acres that are subject to drill-to-earn agreements.
Capital expenditures - In 2013, our capital expenditures were $204.4 million for participation in the drilling of 69 gross (33.5 net) wells, acquire leasehold acres and to construct gathering and salt water disposal facilities.
As of December 31, 2013, we were not in the process of drilling or completing any wells.
As of December 31, 2013, we had a 61% weighted average working interest in producing wells in the Uinta Oil Program.

The Uinta Oil Program includes four areas of development that are located around the basin that we refer to as Blacktail Ridge, Lake Canyon, East Bluebell and South Altamont. The Uinta Oil Program has a sizable acreage position with a long-term drilling inventory, offering us significant growth potential. The resource is a stacked oil play with multiple pay zones, and our drilling program targets multiple zones from the Lower Green River through the Wasatch with vertical wells. The Uinta Oil Program is a core area of operation where we drilled and completed 57 operated wells during 2013.
During 2013, the Company conducted two 80-acre spacing pilot projects, one each in the southern and northern portions of the Blacktail Ridge area. Results to date indicate minimal, if any, interference with appropriate well orientation.

In 2014, the Company will concentrate on development in the East Bluebell area and employ an average of two rigs for approximately 35 wells.

Our oil production is sold at the lease and trucked to markets. Our gas production is gathered and processed by various third parties and we receive residue gas and NGL revenue under percentage of proceeds contracts.

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

Key Statistics

Estimated proved reserves as of December 31, 2013 - 72.6 MMBoe.
Producing wells - We had interests in 956 gross (745.0 net) producing wells as of December 31, 2013, and we serve as the operator in 926 gross wells.
2013 net production - 6,434 MBoe.
Acreage - We held 41,011 net undeveloped acres, including the Cottonwood Gulch prospect, as of December 31, 2013.
Capital expenditures - Our capital expenditures for 2013 were $3.9 million for various gas lift projects.
As of December 31, 2013, we were not in the process of drilling or completing any wells.
At December 31, 2013, we had a 78% weighted average working interest in producing wells in the Piceance Basin.

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. 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 21% for 2014, 24% for 2015 and 26% in 2016.

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 interstate pipelines. 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

9


receive the value of NGLs with Mt. Belvieu pricing for a portion of our production. Our oil production is sold at the lease and trucked to markets.
As a result of the current outlook for natural gas prices, we do not plan to drill in the Piceance Basin in 2014. 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 operations in the Powder River Basin target oil reservoirs.
Powder River Oil
Key Statistics

Estimated reserves as of December 31, 2013 - 5.4 MMBoe.
Producing wells - We had interests in 105 gross (18.1 net) producing wells as of December 31, 2013, and we serve as operator in 17 gross wells.
2013 net production - 437 MBoe.
Acreage - We held 57,806 net undeveloped acres as of December 31, 2013.
Capital expenditures - Our capital expenditures for 2013 were $52.3 million for participation in the drilling of 20 gross (4.8 net) wells and to acquire leasehold acres.
As of December 31, 2013, we were not in the process of drilling or completing any wells.
At December 31, 2013, we had a 15% weighted average working interest in producing wells in the Powder River Basin.

Our Powder River Oil Program targets various Cretaceous oil bearing horizons including the Parkman, Sussex, Shannon, Niobrara, Turner and Frontier formations through horizontal wells. The Powder River Oil Program is an early stage program where we believe there is significant potential for growth in reserves and production from its acreage position. During 2013, we drilled and completed five operated wells and participated in 15 non-operated wells.

In 2014, we plan to participate in approximately 34 gross non-operated wells.

Our oil production is sold at the lease and trucked to markets. Our gas production is gathered and processed by various third parties and we receive residue gas and NGL revenue under percentage of proceeds contracts.

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 all the data prior to January 1, 2013 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. Therefore, we have reported reserve and production data separately for oil, natural gas and NGLs for periods after January 1, 2013 below. This is known as “three streams reporting”.

Proved Reserves

The following table presents our estimated net proved oil, natural gas and NGLs reserves and the present value of our estimated proved reserves at each of December 31, 2013, 2012 and 2011 based on reserve reports prepared by us and audited 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 our reserves estimates at December 31, 2013, 2012 and 2011. NSAI is retained by and reports to the Reserves and EHS 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 and EHS Committee. The Reserves and EHS Committee reviews the final

10


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, 2013.
 
 
As of December 31,
Proved Reserves:
 
2013
 
2012
 
2011
Proved Developed Reserves:
 
 
 
 
 
 
Oil (MMBbls)
 
26.3

 
20.7

 
10.4

Natural gas (Bcf)
 
238.7

 
492.1

 
632.5

NGLs (MMBbls)
 
17.2

 

 

Total proved developed reserves (MMBoe) (1)
 
83.2

 
102.7

 
115.8

Proved Undeveloped Reserves:
 
 
 
 
 
 
Oil (MMBbls)
 
57.2

 
30.1

 
20.2

Natural gas (Bcf)
 
227.7

 
247.1

 
548.6

NGLs (MMBbls) (2)
 
18.6

 

 

Total proved undeveloped reserves (MMBoe) (1)
 
113.7

 
71.2

 
111.6

Total Proved Reserves (MMBoe) (1)
 
197.0

 
174.0

 
227.4


(1)
Total does not add because of rounding.
(2)
The increase in NGLs includes the impact of the Company's conversion to three stream production. Prior to 2013, NGL reserves were included in natural gas data, which impacts the comparability for the periods presented.

The data in the above table represent estimates only. Oil, natural gas and NGLs reserve engineering is an estimation of accumulations of oil, natural gas and NGLs 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, natural gas and NGLs that are ultimately recovered. See “Item 1A. Risk Factors”.

Proved developed oil, natural gas and NGLs reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil, natural gas and NGLs 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.

The following tables illustrate the history of our proved undeveloped reserves from December 31, 2011 through December 31, 2013:
 
 
As of December 31,
Proved Undeveloped Reserves:
 
2013
 
2012
 
2011
Beginning Balance (MMBoe)
 
71.2

 
111.6

 
97.2

Additions from drilling program
 
64.2

 
17.8

 
19.7

Acquisitions
 

 

 
11.9

Engineering/Price revisions
 
8.9

 
(15.2
)
 
9.7

Converted to proved developed
 
(7.8
)
 
(22.8
)
 
(26.1
)
Sold/Expired/Other
 
(22.8
)
 
(20.2
)
 
(0.8
)
Total Proved Undeveloped Reserves (MMBoe)
 
113.7

 
71.2

 
111.6



11


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
Proved undeveloped locations converted to proved developed wells during year
 
49

 
179

 
182

Proved undeveloped drilling and completion capital invested (in millions)
 
$
118.8

 
$
362.2

 
$
209.9

Proved undeveloped facilities capital invested (in millions)
 
$
6.8

 
$
45.6

 
$
20.0

Percentage of proved undeveloped reserves converted to proved developed
 
11.0
%
 
20.4
%
 
22.7
%
Prior year’s proved undeveloped reserves remaining undeveloped at current year end (MMBoe)
 
42.7

 
54.0

 
70.3


At December 31, 2013, our proved undeveloped reserves were 113.7 MMBoe. At December 31, 2012, our proved undeveloped reserves were 71.2 MMBoe. During 2013, 7.8 MMBoe, or 11.0% of our December 31, 2012 proved undeveloped reserves (49 wells), were converted into proved developed reserves and required $118.8 million of drilling and completion capital and $6.8 million of facilities capital. These wells produced 0.7 MMBoe in 2013. During 2013, we added 64.2 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. During 2013, 22.8 MMBoe 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 10.5 MMBoe of proved undeveloped reserves sold in the divestiture of our West Tavaputs properties. Positive engineering and pricing revisions increased proved undeveloped reserves by 8.9 MMBoe. Significant pricing revisions occurred in many of our producing areas, particularly our Piceance Basin natural gas producing area, due to the pricing change from $2.56 per MMBtu CIG for the year ended December 31, 2012 to $3.67 per MMBtu Henry Hub for the year ended December 31, 2013 and from $91.21 per Bbl WTI for the year ended December 31, 2012 to $96.91 per Bbl WTI Cushing for the year ended December 31, 2013. Included in this amount were upward price and performance revisions of 6.6 MMBoe in the Piceance Basin, 3.1 MMBoe in the DJ Basin and 0.3 MMBoe in the Powder River Basin, offset by a 1.1 MMBoe downward engineering revision in the Uinta Oil Program due to lower than predicted performance in some of the wells drilled in the Blacktail Ridge and Lake Canyon areas in 2012. The proved undeveloped reserves from December 31, 2012 that remained in the proved undeveloped reserves category at December 31, 2013 were 42.7 MMBoe.

At December 31, 2012, our proved undeveloped reserves were 71.2 MMBoe. At December 31, 2011, our proved undeveloped reserves were 111.6 MMBoe. During 2012, 22.8 MMBoe, or 20.4% 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 3.9 MMBoe in 2012. During 2012, we added 17.8 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. During 2012, 20.2 MMBoe 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 11.9 MMBoe of proved undeveloped reserves sold in the divestiture of our Wind River Basin and Powder River Basin (coalbed methane) properties and a portion of our Piceance Basin properties. Downward engineering and pricing revisions reduced proved undeveloped reserves by 15.2 MMBoe. 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 21.1 MMBoe 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 0.9 MMBoe. Offsetting these, a positive engineering revision in Uinta Oil Program added 6.8 MMBoe in proved undeveloped reserves, resulting from increased operational focus and engineering and geological study. The proved undeveloped reserves from December 31, 2011 that remained in the proved undeveloped reserves category at December 31, 2012 were 54.0 MMBoe.

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

12


the producing area of the field as of December 31, 2011 (four wells, 0.4 MMBoe). 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 3.3 MMBoe, of which 1.8 MMBoe were attributed to the addition of proved undeveloped reserves in locations greater than one spacing unit from economic producers. Acquisitions added 0.4 MMBoe of the 3.3 MMBoe proved undeveloped reserve addition in Gibson Gulch.

At December 31, 2012, we also revised our total proved reserves downward by 21.2 MMBoe due to the combined effects of year end 2012 pricing and the 20-acre infill drilling performance at the West Tavaputs area, 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 and EHS 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 and oil pricing based on the SEC pricing requirements are supplied by the third party independent engineering firm. Natural gas pricing for the first flow day of every month is collected from Platts Gas Daily Henry Hub price and oil pricing is collected from Bloomberg’s WTI spot price. The average NGL price is based on a percentage of the WTI oil price per barrel.
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 the Reserves and EHS Committee of the Board prior to publication.

Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is Earuch F. Broacha. Mr. Broacha is our Reserves and Technology Manager and became responsible for our reserves estimates starting in 2013. Mr. Broacha earned a Bachelor of Science degree in Chemical Engineering and Petroleum Refining from the Colorado School of Mines in 1978. Mr. Broacha has over 35 years’ experience in reserves and economic evaluations, as well as a broad experience in completions, reservoir simulation and petrophysical analyses.


13


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-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Dan Smith and Mr. John Hattner. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. Mr. Smith is a Licensed Professional Engineer in the State of Texas (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. Mr. Hattner has been practicing consulting petroleum geology at NSAI since 1991. Mr. Hattner is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 559) and has over 30 years of practical experience in petroleum geosciences, with over 20 years experience in the estimation and evaluation of reserves. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

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.
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.
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 in the Financial Statements should not be construed as the

14


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 2013 and 2012, we paid NSAI approximately $550,000 and $446,000, respectively, for auditing our reserves estimates.

Production and Cost History

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


15


 
Year Ended December 31,
2013
 
2012
 
2011
Production Data:
 
 
 
 
 
Oil (MBbls)
3,495

 
2,687

 
1,490

Natural gas (MMcf)
52,685

 
101,486

 
97,856

NGLs (MBbls)
2,199

 

 

Combined volumes (MBoe)
14,475

 
19,601

 
17,799

Daily combined volumes (Boe/d)
39,658

 
53,701

 
48,764

Piceance – Gibson Gulch Production Data (1):
 
 
 
 
 
Oil (MBbls)
331

 
619

 
540

Natural gas (MMcf)
25,470

 
48,072

 
45,606

NGLs (MBbls)
1,858

 

 

Combined volumes (MBoe)
6,434

 
8,631

 
8,141

Daily combined volumes (Boe/d)
17,627

 
23,647

 
22,304

Uinta – West Tavaputs Production Data (1):
 
 
 
 
 
Oil (MBbls)
30

 
61

 
54

Natural gas (MMcf)
21,714

 
34,497

 
31,719

NGLs (MBbls)

 

 

Combined volumes (MBoe)
3,649

 
5,810

 
5,341

Daily combined volumes (Boe/d)
9,997

 
15,918

 
14,633

Uinta – Oil Program Production Data (1):
 
 
 
 
 
Oil (MBbls)
1,996

 
1,479

 
779

Natural gas (MMcf)
3,024

 
2,653

 
1,575

NGLs (MBbls)
142

 

 

Combined volumes (MBoe)
2,642

 
1,921

 
1,042

Daily combined volumes (Boe/d)
7,238

 
5,263

 
2,855

DJ Basin – Production Data (1):
 
 
 
 
 
Oil (MBbls)
757

 
397

 
47

Natural gas (MMcf)
2,016

 
1,264

 
270

NGLs (MBbls)
195

 

 

Combined volumes (MBoe)
1,288

 
608

 
92

Daily combined volumes (Boe/d)
3,529

 
1,666

 
252

Average Costs ($ per Boe):
 
 
 
 
 
Lease operating expense
$
4.85

 
$
3.71

 
$
3.18

Gathering, transportation and processing expense
4.65

 
5.44

 
5.25

Total production costs excluding production taxes
$
9.50

 
$
9.15

 
$
8.43

Production tax expense
1.88

 
1.30

 
2.11

Depreciation, depletion and amortization (2)
19.33

 
17.49

 
16.20

General and administrative (3)
3.39

 
2.66

 
2.68


(1)
The Gibson Gulch area in the Piceance Basin, the Uinta Oil Program in the Uinta Basin and the DJ Basin were the only development areas that contained 15% or more of our total proved reserves as of December 31, 2013. 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 and 2011.
(2)
The depreciation, depletion and amortization (“DD&A”) per Boe as calculated based on the DD&A expense and Boe production data presented in the table for the year ended December 31, 2012 was $16.67. However, the DD&A rate per Boe for the year ended December 31, 2012 of $17.49, as presented in the table above, excludes fourth quarter production of 911 MBoe 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 $15.8 million, $16.4

16


million and $19.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. If included, these non-cash stock based compensation expenses would have increased general and administrative expense by $1.09, $0.84 and $1.07 per Boe for the years ended December 31, 2013, 2012 and 2011, 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 administrative expense for a total of $64.9 million, $68.7 million and $66.8 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013 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.
 
 
Oil
 
Gas
Basin
 
Gross Wells
 
Net Wells
 
Gross Wells
 
Net Wells
Piceance
 

 

 
956.0

 
745.0

Uinta Oil Program
 
294.0

 
169.2

 
5.0

 
0.9

DJ
 
150.0

 
80.9

 
174.0

 
122.4

Powder River Oil
 
101.0

 
17.3

 
4.0

 
0.8

Other
 
11.0

 
4.9

 
3.0

 
0.7

Total
 
556.0

 
272.3

 
1,142.0

 
869.8


Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2013 relating to our leasehold acreage.
 
Developed Acreage (1)
 
Undeveloped Acreage (2)
 
Basin/Area
Gross
 
Net
 
Gross
 
Net
 
Piceance
11,866

 
8,675

 
46,962

 
41,011

(3) 
Uinta Oil Program
62,362

 
39,447

 
157,803

 
70,795

(4) 
DJ
43,786

 
34,255

 
130,877

 
60,672

 
Powder River Oil
31,592

 
10,028

 
130,447

 
57,806

 
Other
13,306

 
12,054

 
678,017

 
479,473

 
Total
162,912

 
104,459

 
1,144,106

 
709,757

(3)(4) 

(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)
Includes 40,312 gross and 36,281 net acreage associated with the Cottonwood Gulch property.
(4)
Does not include an additional 153,931 gross and 67,500 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, 2013, the expiration periods of the gross and net acres that are subject to leases summarized in the above table of undeveloped acreage.

17


 
Undeveloped Acres Expiring
 
Years Ending:
Gross
 
Net
 
December 31, 2014
286,004

 
117,416

 
December 31, 2015
194,549

 
125,552

 
December 31, 2016
164,601

 
113,601

 
December 31, 2017
111,594

 
73,894

 
December 31, 2018 and later
387,358

 
279,294

(1) 
Total
1,144,106

 
709,757

 

(1)
Includes 207,162 gross and 123,441 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,
 
2013
 
2012
 
2011
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development
 
 
 
 
 
 
 
 
 
 
 
Productive
164.0

 
85.8

 
324.0

 
218.7

 
279.0

 
191.4

Dry

 

 

 

 

 

Exploratory
 
 
 
 
 
 
 
 
 
 
 
Productive

 

 
3.0

 
1.5

 
6.0

 
3.3

Dry

 

 
3.0

 
2.7

 
3.0

 
1.4

Total
 
 
 
 
 
 
 
 
 
 
 
Productive
164.0

 
85.8

 
327.0

 
220.2

 
285.0

 
194.7

Dry

 

 
3.0

 
2.7

 
3.0

 
1.4


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. Independent contractors engaged by us provide the majority of the equipment and personnel associated with these activities. We do construct, operate and maintain a majority of the gas gathering facilities associated with our gas fields. 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 production from our operated properties; other than in the Piceance Basin, where we market natural gas, our natural gas and related NGLs are marketed by third parties under percentage of proceeds (“POP”)

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contracts. 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 development and production business. However, based on where we operate and the availability of other purchasers and markets, we believe that the loss of any of our major purchasers would not have a material adverse effect on our financial condition and results of operations as there are competitive markets available.

During 2013, five customers accounted for 49% of our oil and gas production revenues. 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. 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”.

In the Piceance Basin, 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 natural 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.

Our oil production is collected in tanks on location 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.

The following table sets forth information about material long-term firm transportation contracts for pipeline capacity and firm gathering and processing contracts, both of which typically require a demand charge. 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.

Type of Arrangement
 
Pipeline System / Location
 
Deliverable Market
 
Gross Deliveries (MMBtu/d)
 
Term
Firm Gathering
 
Summit Midstream
 
Rocky Mountains
 
Varies
 
01/11 – 12/20
Firm Transport
 
WIC Overthrust (1)
 
Rocky Mountains
 
50,000
 
08/11 – 07/21
Firm Transport
 
Questar Pipeline
 
Rocky Mountains
 
12,000
 
11/05 – 10/15
Firm Transport
 
Rockies Express
 
Northeast
 
25,000
 
06/09 – 11/19
Firm Transport
 
Ruby Pipeline
 
West Coast
 
50,000
 
08/11 – 07/21

(1)
This contract was entered into in conjunction with the Ruby Pipeline contract; and therefore has an end date of 10 years from the in-service date of the Ruby Pipeline.

Hedging Activities

We have an active commodity hedging program, the purpose of which is to mitigate the risks of volatile prices of oil, natural gas, and NGLs. Typically, we intend to hedge approximately 50% to 70% of our oil, natural gas and NGLs production

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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 65% of our expected 2014 production and 20% of our expected 2015 production at price levels that provide some economic certainty to our capital investments. To date 9 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 intensely competitive, and we compete with a large number of other companies, some of which have greater resources. Many of these companies not only explore for and produce oil, natural gas and NGLs, 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, natural gas and NGLs 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, natural gas and NGLs market prices. Our larger or integrated competitors are better able to absorb the burden of existing, and any changes to, federal, state, local and Native American tribal laws and regulations than we can, 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 exploratory prospects and producing oil, natural gas and NGLs properties.

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 developed 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 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 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, natural gas and NGLs 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.

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;     

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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, natural gas and NGLs 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, 2013, 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, natural gas and NGLs 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 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 are currently exempt from regulation under the hazardous waste provisions of RCRA, 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 reverse the exemption.

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

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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, stormwater 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 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. It is anticipated that within the next two years, a federal rulemaking will be held to revise the definition of a regulated “water of the United States”. This rulemaking may expand the definition of “water of the United States” to include certain waters, including wetlands, not currently regulated. This definition would subject those waters to permitting under the Clean Water Act, including requiring permits under Section 404 of the Clean Water Act for wetlands development. 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. The state of Colorado is in the process of an air quality rulemaking for state oil and gas operations that could result in state air regulations that are more stringent than those imposed by EPA, including regulating methane emissions. The rulemaking will conclude in February 2014. These state and federal 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

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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. 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 and surface facilities;
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 and 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.

Under the direction of Congress, the EPA has undertaken a study of the effect, if any, 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 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

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which we conduct or plan to conduct operations. Furthermore, moratoria on hydraulic fracturing have been imposed in certain localities where we do not have operations and legislation has been proposed at local, state and federal levels.

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 Basin 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 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 24, 2014, we had 258 employees of whom 164 work in our Denver office and 94 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.

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Offices

As of December 31, 2013, 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

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 and EHS 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 13, 2013, 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.
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

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

We have acquired 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 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, natural gas and NGLs 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, natural gas or NGLs are 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

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results in our plays may be more uncertain than in other 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 formations to maximize recoveries will be ultimately successful when used in our prospects. As a result, we may incur future dry hole costs and or impairment charges due to any of these factors.

Oil and gas prices are volatile and a decline in oil, natural gas and natural gas liquids 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, natural gas and NGLs. 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, natural gas and NGLs prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil, natural gas and NGLs may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

the domestic and foreign supply of oil, natural gas and NGLs;
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.

Lower oil, natural gas and NGLs prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil, natural gas and NGLs 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.

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, natural gas and NGLs 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.

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 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

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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”.

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 2014. The U.S. Energy Policy Act of 2005, which generally exempts hydraulic fracturing from regulation under the Underground Injection Control program of 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 and, thus, in violation of the notice-and-comment rulemaking 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. A final report is expected in 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. In 2012 and 2013 the U.S. Department of the Interior proposed federal regulations to require the disclosure of the chemicals used in the fracturing process on public lands, along with other regulations relating to oil and gas production on federal lands. These proposed regulations could serve as a model for state regulation regarding the process.

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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”) and put into effect in 2012, 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. 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 delays, 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 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.

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, natural gas and NGLs 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 Uinta oil production has a higher paraffin content which limits the number of refiners able to purchase it as feedstock. 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.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and 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:

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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.

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 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.

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, natural gas and NGL reserves.

The oil and 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 acquisition of oil, natural gas and NGL 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, natural gas and NGLs 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, natural gas and NGLs 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, natural gas and NGLs reserves as well as our revenues and results of operations.

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, oil, natural gas and NGLs 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, natural gas and NGLs from these or any other potential drilling locations. As such, our actual drilling activities may differ materially from those presently identified, which could adversely affect our business.

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

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The oil and 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, natural gas and NGLs, 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 producing oil, natural gas and NGLs properties and exploration and development 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, natural gas and NGLs 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 properties and exploration and development 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 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.


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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 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, natural gas and NGLs cannot be measured in an exact way. Oil, natural gas and NGLs reserve engineering requires estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGLs 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.

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

Producing oil, natural gas and NGL 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, natural gas and NGL 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 use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil, natural gas and NGLs, 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.

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

Oil, natural gas and NGLs 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, natural gas and NGLs

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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, natural gas and NGLs 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 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, natural gas and NGLs 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, natural gas and NGLs 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.

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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 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 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. Previous proposed legislation included 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.

Risks Related to Our Common Stock


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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 could 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 5% Convertible Senior Notes due 2028 (“Convertible Notes”), our 7.625% Senior Notes due 2019 (“7.625% Senior 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, 2013, the total outstanding principal amount of our total indebtedness was approximately $983.7 million, and we had approximately $484.0 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. The borrowing base is dependent on our proved reserves and was, as of December 31, 2013, $625.0 million based on our June 30, 2013 proved reserves, adjusted for the sale of our West Tavaputs properties, and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. As of December 31, 2013, the outstanding principal balance under our Amended Credit Facility was $115.0 million.

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;

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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.

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, natural gas and NGL 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.


35


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.


36


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
2013
 
 
 
First Quarter
$
21.64

 
$
15.50

Second Quarter
24.23

 
17.78

Third Quarter
25.47

 
20.34

Fourth Quarter
30.69

 
24.08

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


On January 24, 2014, the closing sales price for our common stock as reported by the NYSE was $28.16 per share.

Holders. On December 31, 2013, the number of holders of record of our common stock was 120.

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, 2013.

Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2013:
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, 2013
 
500

 
$
26.03

 
0

 
0

November 1 - 30, 2013
 
3,343

 
$
27.63

 
0

 
0

December 1 - 31, 2013
 
9,677

 
$
26.60

 
0

 
0

Total
 
13,520

 
$
26.83

 
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.

Stockholder Return Performance Presentation


37


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, 2008, 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, 2008.

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


 
December 31,
2008
 
December 31,
2009
 
December 31,
2010
 
December 31,
2011
 
December 31,
2012
 
December 31,
2013
BBG
$
100

 
$
147

 
$
195

 
$
161

 
$
84

 
$
129

S&P MidCap 400- Energy
100

 
183

 
239

 
214

 
211

 
266

S&P 500
100

 
126

 
146

 
149

 
172

 
223


Item 6.
Selected Financial Data.

The following table presents our selected historical financial data for the years ended December 31, 2013, 2012, 2011, 2010 and 2009. 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.

Selected Historical Financial Information

The consolidated statement of operations information for the years ended December 31, 2013, 2012 and 2011 and the balance sheet information as of December 31, 2013 and 2012 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, 2010 and 2009 and the balance sheet information at December 31, 2011, 2010 and 2009 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.

38



 
Year Ended December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
 
(in thousands, except per share data)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Operating and Other Revenues:
 
 
 
 
 
 
 
 
 
Oil, gas and NGL production (1)
$
565,555

 
$
700,639

 
$
780,751

 
$
708,452

 
$
647,839

Other
2,538

 
(444
)
 
4,873

 
591

 
4,891

Total operating and other revenues
568,093

 
700,195

 
785,624

 
709,043

 
652,730

Operating Expenses:
 
 
 
 
 
 
 
 
 
Lease operating expense
70,217

 
72,734

 
56,603

 
52,040

 
46,492

Gathering, transportation and processing expense
67,269

 
106,548

 
93,423

 
69,089

 
56,608

Production tax expense
27,172

 
25,513

 
37,498

 
32,738

 
13,197

Exploration expense
337

 
8,814

 
3,645

 
9,121

 
3,227

Impairment, dry hole costs and abandonment expense
238,398

 
67,869

 
117,599

 
44,664

 
52,285

Depreciation, depletion and amortization expense
279,775

 
326,842

 
288,421

 
260,665

 
253,573

General and administrative expense (2)
49,069

 
52,222

 
47,744

 
40,884

 
37,940

Non-cash stock-based compensation
expense (2)
15,833

 
16,444

 
19,036

 
16,908

 
16,458

Total operating expenses
748,070

 
676,986

 
663,969

 
526,109

 
479,780

Operating Income (Loss)
(179,977
)
 
23,209

 
121,655

 
182,934

 
172,950

Other Income and Expense:
 
 
 
 
 
 
 
 
 
Interest income and other income (expense)
1,646

 
155

 
(397
)
 
402

 
438

Interest expense
(88,507
)
 
(95,506
)
 
(58,616
)
 
(44,302
)
 
(30,647
)
Commodity derivative gain (loss)
(23,068
)
 
72,759

 
(14,263
)
 
(10,579
)
 
(54,567
)
Gain (loss) on extinguishment of debt
(21,460
)
 
1,601

 

 

 

Total other income and expense
(131,389
)
 
(20,991
)
 
(73,276
)
 
(54,479
)
 
(84,776
)
Income (Loss) before Income Taxes
(311,366
)
 
2,218

 
48,379

 
128,455

 
88,174

Provision for (Benefit from) Income Taxes
(118,633
)
 
1,636

 
17,672

 
47,953

 
37,956

Net Income (Loss)
$
(192,733
)
 
$
582

 
$
30,707

 
$
80,502

 
$
50,218

Net Income (Loss) per Common Share:
 
 
 
 
 
 
 
 
 
Basic
$
(4.06
)
 
$
0.01

 
$
0.66

 
$
1.78

 
$
1.12

Diluted
$
(4.06
)
 
$
0.01

 
$
0.65

 
$
1.75

 
$
1.12

Weighted average common shares outstanding, basic
47,496.9

 
47,194.7

 
46,535.6

 
45,217.6

 
44,723.1

Weighted average common shares outstanding, diluted
47,496.9

 
47,354.0

 
47,236.7

 
45,877.4

 
45,036.0



39


 
Year Ended December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
 
(in thousands)
Selected Cash Flow and Other Financial Data:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(192,733
)
 
$
582

 
$
30,707

 
$
80,502

 
$
50,218

Depreciation, depletion, impairment and amortization
506,326

 
364,190

 
388,699

 
276,281

 
273,227

Other non-cash items
(32,600
)
 
29,281

 
55,102

 
101,079

 
132,885

Change in assets and liabilities
(15,728
)
 
(5,617
)
 
4,840

 
(10,674
)
 
24,414

Net cash provided by operating activities
$
265,265

 
$
388,436

 
$
479,348

 
$
447,188

 
$
480,744

Capital expenditures (3)(4)
$
474,031

 
$
962,573

 
$
987,341

 
$
473,268

 
$
406,420


(1)
Oil, gas and NGL 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 $64.9 million, $68.7 million, $66.8 million, $57.8 million and $54.4 million for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, 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 liabilities of negative $6.6 million and $7.5 million, $12.1 million, $1.3 million and negative $1.2 million for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $12.2 million, $39.3 million, $21.0 million, $38.2 million and $35.9 million for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively. Also includes furniture, fixtures and equipment costs of $1.3 million, $6.9 million, $8.9 million, $2.1 million and $2.1 million for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively.
(4)
Not deducted from the amount are $306.3 million, $325.3 million, $2.0 million, $2.9 million and $3.7 million of proceeds received principally from the sale of interests in oil and gas properties during the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively.
 
As of December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
 
(in thousands)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
54,595

 
$
79,445

 
$
57,331

 
$
58,690

 
$
54,405

Other current assets
102,652

 
148,894

 
189,012

 
148,958

 
125,634

Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment
2,184,183

 
2,584,979

 
2,383,196

 
1,796,288

 
1,639,212

Other property and equipment, net of depreciation
18,313

 
26,358

 
23,568

 
15,531

 
14,444

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

 

 

 

 
5,604

Other assets
21,770

 
29,773

 
34,823

 
19,033

 
26,824

Total assets
$
2,381,513

 
$
2,869,449

 
$
2,687,930

 
$
2,038,500

 
$
1,866,123

Current liabilities
$
192,719

 
$
213,133

 
$
233,198

 
$
165,957

 
$
153,292

Long-term debt
979,082

 
1,156,654

 
882,240

 
404,399

 
402,250

Other long-term liabilities
203,994

 
316,887

 
353,654

 
327,182

 
282,026

Stockholders' equity
1,005,718

 
1,182,775

 
1,218,838

 
1,140,962

 
1,028,555

Total liabilities and stockholders' equity
$
2,381,513

 
$
2,869,449

 
$
2,687,930

 
$
2,038,500

 
$
1,866,123


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

40



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 by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations plans while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices and from the settlement of commodity hedges. Due to current and expected commodity prices for oil, natural gas and NGLs, we are focused on developing oil assets where we have established a long-term inventory of drilling locations. As a result, 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 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.

We are committed to exploring for, developing and producing oil, natural gas and NGLs 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 or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our 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.

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. Therefore, we report below reserve and production data for oil, natural gas and NGLs for periods after January 1, 2013. This is known as “three streams reporting”. For periods prior to January 1, 2013, we presented our production and reserve data for oil and natural gas, which combined NGLs with the natural gas stream, and did not separately report NGLs. This change impacts the comparability of 2013 with prior periods.

As of January 1, 2014, we are reporting reserves, production and the related metrics in Boe instead if Mcfe, because of our combined exit production rate for 2013 of 58% for oil and NGLs and as we continue to focus on the development of our oil prospects.

Because of our growth through acquisitions and, more recently, development of our properties and sale of non-core properties in 2012 and 2013, 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.


41


 
Year Ended December 31,
 
2013
 
2012
 
2011
Estimated net proved reserves (MMBoe)
197.0

 
174.0

 
227.4

Standardized measure (1) (in millions)
$
1,377.5

 
$
1,166.7

 
$
1,616.1


(1)
December 31, 2013 was based on average prices of $96.91 WTI for oil, $3.67 Henry Hub for natural gas and $39.75 for NGLs using the current SEC requirements. 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.

The following table summarizes the average sales prices received for oil, natural gas and NGLs, before the effects of hedging contracts, for the years indicated:
 
Year Ended December 31,
 
2013
 
2012
 
2011
Oil (per Bbl)
$
82.61

 
$
79.39

 
$
81.97

Natural gas (per Mcf) (1)
$
3.96

 
$
4.00

 
$
5.71

NGLs (per Bbl) (1)
$
27.02

 
$

 
$


(1)
Prior to 2013, NGL volumes and revenues were included within natural gas production data, which impacts the comparability for the two periods presented.

The following table summarizes the average sales prices received for oil, natural gas and NGLs, after the effects of hedging contracts, for the years indicated:
 
Year Ended December 31,
 
2013
 
2012
 
2011
Oil (per Bbl)
$
82.38

 
$
84.96

 
$
80.63

Natural gas (per Mcf) (1)
$
4.16

 
$
5.07

 
$
6.46

NGLs (per Bbl) (1)
$
28.31

 
$

 
$


(1)
Prior to 2013, NGL volumes and revenues were included within natural gas production data, which impacts the comparability for the two periods presented.

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 and other financial derivative instruments. We currently have hedged approximately 65% of our expected 2014 production and 20% of our expected 2015 production at price levels that provide some economic certainty to our capital investments. We focus our efforts on increasing oil, natural gas and NGLs 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, gas and NGLs 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 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

42


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, 2013 Compared with Year Ended December 31, 2012

The following table sets forth selected operating data for the periods indicated:
 
 
Year Ended December 31,
 
Increase (Decrease)
2013
 
2012
 
Amount
 
Percent
($ in thousands, except per unit data)
Operating Results:
 
 
 
 
 
 
 
Operating and Other Revenues
 
 
 
 
 
 
 
Oil, gas and NGL production
$
565,555

 
$
700,639

 
$
(135,084
)
 
(19
)%
Other
2,538

 
(444
)
 
2,982

 
*nm

Total operating and other revenues
$
568,093

 
$
700,195

 
$
(132,102
)
 
(19
)%
Operating Expenses
 
 
 
 
 
 
 
Lease operating expense
$
70,217

 
$
72,734

 
$
(2,517
)
 
(3
)%
Gathering, transportation and processing expense
67,269

 
106,548

 
(39,279
)
 
(37
)%
Production tax expense
27,172

 
25,513

 
1,659

 
7
 %
Exploration expense
337

 
8,814

 
(8,477
)
 
(96
)%
Impairment, dry hole costs and abandonment expense
238,398

 
67,869

 
170,529

 
*nm

Depreciation, depletion and amortization
279,775

 
326,842

 
(47,067
)
 
(14
)%
General and administrative expense (1)
49,069

 
52,222

 
(3,153
)
 
(6
)%
Non-cash stock-based compensation expense (1)
15,833

 
16,444

 
(611
)
 
(4
)%
Total operating expenses
$
748,070

 
$
676,986

 
$
71,084

 
11
 %
Production Data (2):
 
 
 
 
 
 
 
Oil (MBbls)
3,495

 
2,687

 
808

 
30
 %
Natural gas (MMcf)
52,685

 
101,486

 
(48,801
)
 
(48
)%
NGLs (MBbls)
2,199

 

 
2,199

 
*nm

Combined volumes (MBoe)
14,475

 
19,601

 
(5,126
)
 
(26
)%
Daily combined volumes (Boe/d)
39,658

 
53,701

 
(14,043
)
 
(26
)%
Average Realized Prices (2)(3):
 
 
 
 
 
 
 
Oil (per Bbl)
$
82.38

 
$
84.96

 
$
(2.58
)
 
(3
)%
Natural gas (per MMcf) (4)
4.16

 
5.07

 
(0.91
)
 
(18
)%
NGLs (per Bbl)
28.31

 

 
28.31

 
*nm

Combined (per Boe)
39.35

 
37.90

 
1.45

 
4
 %
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expense
$
4.85

 
$
3.71

 
$
1.14

 
31
 %
Gathering, transportation and processing expense
4.65

 
5.44

 
(0.79
)
 
(15
)%
Production tax expense
1.88