10-K 1 bbg-12312015x10xk.htm 10-K 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, 2015
or
 
o
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
 
 
 
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.
o  Yes   þ  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.
o  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    o  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    o  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. þ 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
o  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 30, 2015 based on the $8.59 closing price of the registrant's common stock on the New York Stock Exchange was $419,405,504.

As of February 2, 2016, the registrant had 49,854,697 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 2016 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant's fiscal year ended December 31, 2015.




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:

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. 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 or 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.

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.

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.

EBITDAX. Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.

EHS. Environmental Health and Safety.

Environmental Assessment. A study that can be required prior to drilling a federal well.

Environmental Impact Statement. A more detailed study of the potential direct, indirect and cumulative impacts of a federal project that is subject to public review and potential litigation.

EPA. The United States Environmental Protection Agency.

E&P waste. Exploration and production waste, intrinsic to oil and gas drilling and production operations.

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.


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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.

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.

Infill drilling. The addition of wells in a field that decreases average well spacing. This practice both accelerates expected recovery and increases estimated ultimate recovery in heterogeneous reservoirs by improving the continuity between injectors and producers. As well spacing is decreased, the shifting well patterns alter the formation-fluid flow paths and increase sweep to areas where greater hydrocarbon saturations exist.

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 Mt. Belvieu, TX settlement point price as quoted by Oil Price Information Service.

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.

Percentage of proceeds contracts. Under percentage of proceeds (POP) contracts, processors receive an agreed upon percentage of the actual proceeds of the sale of the dry natural gas and NGLs.

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.

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


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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 producing reserves. 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. 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.

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.


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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");
availability of capital at a reasonable cost;
legislative or regulatory changes that can affect our ability to permit wells and conduct operations, including ballot initiatives seeking moratoria or bans on drilling or 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, regulatory penalties or other matters that may not be covered by an effective indemnity or insurance; and
other uncertainties, including the 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 our expectations will be realized or that future forward-looking events and circumstances will occur as anticipated. 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, 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 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 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.

Oil prices declined severely beginning in 2014, and price decreases continued through 2015 and into 2016. Natural gas and NGL prices have experienced decreases of comparable magnitude over the same period. These decreases have increased the volatility and amplitude of the other risks facing us as described in this report and have impacted our average realized unit price and are having an impact on our business and financial condition. Commodity prices are inherently volatile and are influenced by many factors outside of our control. Our activities and capital budget maintain flexibility using what we believe to be conservative sales price assumptions and our existing hedge position. If commodity prices continue at current levels or lower, our capital availability, liquidity and profitability are likely to be adversely affected as current hedges are realized in 2016 and 2017.

As we go through 2016, our priority remains ensuring ample liquidity and protecting the strength of our balance sheet, and we will adjust our development plans as necessary to this end. We remain in close contact with the banks in our credit facility and are evaluating the increased risk that lenders may seek to reduce our borrowing base due to their exposure to the energy industry or for other reasons. Further, we continue to monitor debt, equity and hedging markets for opportunities to strengthen our liquidity position.

We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders expectations and regulatory requirements.

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 maintain a website at the address http://www.billbarrettcorp.com. We are not including the information contained on our website as part of, or incorporating it by reference into, this report. 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 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

6


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, 2015:

Basin/Area
 
State
 
Estimated Net
Proved Reserves
(MMBoe) (1)
 
December 2015 Average Daily Net Production
(Boe/d)
 
Net Producing Wells (2)
 
Net Undeveloped Acreage
 
Denver-Julesburg
 
CO/WY
 
62.3

 
13,332

 
163.3

 
33,796

 
Uinta Oil Program
 
UT
 
21.4

 
3,971

 
145.9

 
31,283

(3) 
Other
 
Various
 

 
30

 
5.5

 
213,390

(4) 
Total
 
 
 
83.7

 
17,333

 
314.7

 
278,469



(1)
Our proved reserves were determined in accordance with SEC guidelines, using the average of the prices on the first day of each month in 2015 for natural gas (Henry Hub price) and oil (WTI Cushing price), which averaged $2.59 per MMBtu of natural gas and $50.28 per barrel of oil in 2015, respectively, without giving effect to hedging transactions. The average NGL price of $20.37 per barrel was based on a Mt Belvieu pricing using a historical composite percentage. Our reserves estimates are based on a reserve report prepared by us and audited by our independent third party petroleum engineers. See "– Oil and Gas Data – Proved Reserves".
(2)
Net wells are the sum of our fractional working interests owned in gross wells.
(3)
Excludes an additional 51,806 net undeveloped acres that are subject to drill-to-earn agreements.
(4)
Other includes 107,171 and 63,367 net undeveloped acres in the Paradox and Deseret Basins, respectively.

Areas of Operation


Overview

As of December 31, 2015, we have two key areas of production: The Denver-Julesburg Basin ("DJ Basin") and the Uinta Oil Program in the Uinta Basin.

The following table shows changes in the mix of oil, natural gas and NGLs for both production and reserves over the periods presented:

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Year Ended December 31,
 
2015
 
2014
 
2013
 
Oil
 
Natural
Gas
 
NGLs
 
Oil
 
Natural
Gas
 
NGLs
 
Oil
 
Natural
Gas
 
NGLs
Production
67
%
 
20
%
 
13
%
 
44
%
 
40
%
 
16
%
 
24
%
 
61
%
 
15
%
Proved reserves
66
%
 
20
%
 
14
%
 
69
%
 
21
%
 
10
%
 
43
%
 
39
%
 
18
%

Production for the years ended December 31, 2014 and 2013 and proved reserves for the year ended December 31, 2013 include legacy natural gas producing properties that have been sold.

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, 2015 - 62.3 MMBoe.
Producing wells - We had interests in 280 gross (163.3 net) producing wells as of December 31, 2015, and we serve as operator in 169 gross wells.
2015 net production - 4,775 MBoe.
Acreage - We held 33,796 net undeveloped acres as of December 31, 2015.
Capital expenditures - Our capital expenditures for 2015 were $250.3 million for participation in the drilling of 69 gross (44.3 net) wells, acquisition of leasehold acres and construction of gathering facilities.
As of December 31, 2015, we were drilling 1 gross well (1 net), and we were waiting to complete 19 gross (18 net) wells within the DJ Basin.
As of December 31, 2015, we had a 72% weighted average working interest in our producing wells in the DJ Basin.
 
Our DJ Basin acreage was acquired predominantly through two acquisitions completed in August 2011 and July 2012. During the year ended December 31, 2015, we sold certain non-core assets in two separate transactions closing on October 21, 2015 and November 30, 2015, respectively. These asset sales included approximately 23,000 net acres (76% proved developed) and interests in legacy vertical producing wells for cash proceeds of $30.7 million. The divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized in 2016.

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 opportunities with potential acreage additions to our current leasehold position, possible development of additional formations, increased utilization of extended reach (long lateral) horizontal wells, well completion optimization and ongoing cost reduction.

The DJ Basin is a core area of operation where we drilled 43 operated wells and completed 39 operated wells in 2015 and had one rig operating at the end of 2015. In 2015, we focused on drilling extended reach horizontal wells in the Niobrara B and Niobrara C formations in the Northeast Wattenberg area of the DJ Basin, continuing to optimize our completion technology and establishing a scalable development program. The combination of this development along with nearby competitor activity continued to de-risk our approximate net 40,000 acres in the area.

The 2016 drilling program will be reduced relative to 2015 due to low commodity prices. Currently we are utilizing one rig in the DJ Basin. This rig will be released in the first quarter of 2016. Our capital budget contemplates that drilling will resume in the third quarter of 2016; however, we may elect to accelerate or delay drilling further depending on industry conditions. The 2016 operated drilling program will focus on drilling extended reach wells (9,200 foot laterals) and will be developed on 40 to 60 acre well density. In addition, we anticipate minimal participation in non-operated wells. This program may be modified throughout 2016 as business conditions and operating results warrant.

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

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Uinta Basin

The Uinta Basin is located in northeastern Utah.

Key Statistics

Estimated proved reserves as of December 31, 2015 - 21.4 MMBoe.
Producing wells - We had interests in 242 gross (145.9 net) producing wells as of December 31, 2015, and we serve as operator in 174 gross wells.
2015 net production - 1,790 MBoe.
Acreage - We held 31,283 net undeveloped acres as of December 31, 2015, along with 51,806 net undeveloped acres that are subject to drill-to-earn agreements.
Capital expenditures - In 2015, our capital expenditures were $34.6 million for participation in the drilling of 19 gross (11.5 net) wells, acquisition of leasehold acres and construction of gathering and salt water disposal facilities.
As of December 31, 2015, we were not in the process of drilling or completing any wells.
As of December 31, 2015, we had a 56% weighted average working interest in our producing wells in the Uinta Oil Program.

The Uinta Oil Program includes three areas of development located in the Uinta Basin that we refer to as Blacktail Ridge, Lake Canyon and East Bluebell. On November 30, 2015, we sold certain non-core assets located in the Uinta Basin, which included approximately 17,600 net acres and interests in producing wells for cash proceeds of $26.0 million. The divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized in 2016.

The Uinta Oil Program has a sizable acreage position with a long-term drilling inventory and a significant resource in place. 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 formations with vertical wells.

In 2016, the Company has no plans to drill and develop any acreage and we anticipate minimal participation in non-operated wells. This program may be modified throughout 2016 as business conditions and operating results warrant.

Our oil production in the Uinta Basin is sold at the lease and trucked to markets. Our gas production in the Uinta Basin 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

Proved Reserves

The following table presents our estimated net proved oil, natural gas and NGL reserves and the present value of our estimated proved reserves at each of December 31, 2015, 2014 and 2013 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, such an audit is required under our revolving credit agreement. 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, 2015, 2014 and 2013. 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 NSAI's estimates. However, in the aggregate, NSAI's 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 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, 2015.

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As of December 31,
Proved Reserves:(1)(2)
 
2015
 
2014
 
2013
Proved Developed Reserves:
 
 
 
 
 
 
Oil (MMBbls)
 
27.2

 
29.3

 
26.3

Natural gas (Bcf)
 
45.2

 
50.6

 
238.7

NGLs (MMBbls)
 
5.1

 
3.8

 
17.2

Total proved developed reserves (MMBoe) (3)
 
39.8

 
41.5

 
83.2

Proved Undeveloped Reserves:
 
 
 
 
 
 
Oil (MMBbls)
 
28.3

 
54.5

 
57.2

Natural gas (Bcf)
 
52.8

 
103.3

 
227.7

NGLs (MMBbls)
 
6.8

 
9.0

 
18.6

Total proved undeveloped reserves (MMBoe) (3)
 
43.9

 
80.8

 
113.7

Total Proved Reserves (MMBoe) (3)
 
83.7

 
122.3

 
196.9


(1)
Our proved reserves were determined in accordance with SEC guidelines, using the average of the prices on the first day of each month in 2015 for natural gas (Henry Hub price) and oil (WTI Cushing price), or $2.59 per MMBtu of natural gas and $50.28 per barrel of oil, respectively, without giving effect to hedging transactions. The average NGL price of $20.37 per barrel was based on a Mt Belvieu pricing using a historical composite percentage. We currently do not include future reclamation costs net of salvage value in the calculation of our proved reserves. 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)
The comparability of the proved reserves for the periods presented are impacted by the Piceance Divestiture and Powder River Oil Divestiture in 2014. See Note 4 of the Notes to Consolidated Financial Statements for more information related to these divestitures.
(3)
Total does not add due to rounding.

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 proved 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 proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking, unless the specific circumstances justify a longer time. No proved undeveloped reserves can be attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

The following tables illustrate the history of our proved undeveloped reserves from December 31, 2013 through December 31, 2015:


10


 
 
As of December 31,
Proved Undeveloped Reserves:
 
2015
 
2014
 
2013
 
 
(MMBoe)
Beginning balance
 
80.8

 
113.7

 
71.2

Additions from drilling program
 
2.6

 
12.5

 
64.2

Acquisitions
 

 
7.4

 

Engineering revisions
 
1.3

 
(6.0
)
 
4.6

Price revisions
 
(18.0
)
 

 
4.3

Converted to proved developed
 
(8.1
)
 
(10.2
)
 
(7.8
)
Sold/ expired/ other
 
(14.7
)
 
(36.6
)
 
(22.8
)
Total proved undeveloped reserves (1)
 
43.9

 
80.8

 
113.7


 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
Proved undeveloped locations converted to proved developed wells during year
 
35

 
65

 
49

Proved undeveloped drilling and completion capital invested (in millions)
 
$
165.3

 
$
227.5

 
$
118.8

Proved undeveloped facilities capital invested (in millions)
 
$
5.0

 
$
9.5

 
$
6.8

Percentage of proved undeveloped reserves converted to proved developed (2)
 
10.0
%
 
9.0
%
 
11.0
%
Prior year's proved undeveloped reserves remaining undeveloped at current year end (MMBoe)
 
40.8

 
66.8

 
42.7


(1)
Our development plan for drilling proved undeveloped wells represents an investment decision to drill these proved undeveloped locations within the five year development window allowed at the time the applicable proved undeveloped reserve is booked. Our development plan gives us the flexibility to develop the DJ Basin proved undeveloped locations with a one rig program over three years and the Uinta Basin proved undeveloped locations with a one rig program over two years. However, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as changes in commodity prices, anticipated cash flows and projected rate of return, access to capital, new opportunities with better returns on investment that were not known at the time of the reserve report, asset acquisitions and/or sales and actions or inactions of other co-owners or industry operators. As such, the relative proportion of total proved undeveloped locations that we develop may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled proved undeveloped locations, in favor of projects with a more attractive rate of return, leading us to deviate from our original development plan.
(2)
Over the last three years our asset portfolio has significantly changed, resulting in a change in development focus. Due to low natural gas prices in 2012, drilling was halted in the Piceance Basin and the West Tavaputs area of the Uinta Basin, both of which were highly mature infill development programs and which together included the majority of our then remaining proved undeveloped drilling inventory; therefore, a relatively higher percentage of proved undeveloped locations were being converted to proved developed producing. Subsequently, the West Tavaputs assets were divested in 2013 and the Piceance assets were divested in 2014 with no further drilling activity. During 2013, 2014 and 2015 the development program was focused on the oil assets located in the DJ and Uinta Basins which are still relatively immature in their development as compared to the divested gas assets. Given our acreage positions in both the DJ and Uinta Basins, we concentrated on developing unproven locations in order to assess the extent of the plays across our acreage and to develop leases that would have expired. In 2016 with our reduced development program, we still anticipate continuing to develop a mix of proved undeveloped locations and unproven locations. Even with the anticipated reduction of development activity in 2016, we expect the 2016 percentage of our proved undeveloped reserves converted to proved developed to almost double to approximately 19% relative to 2014 and 2015. Given the lower commodity price, development is anticipated to be concentrated in areas of higher certainty. We would expect this to contribute to a higher conversion rate and a reduction in the number of proved undeveloped locations added as a result of development activity.
    

11


At December 31, 2015, our proved undeveloped reserves were 43.9 MMBoe. At December 31, 2014, our proved undeveloped reserves were 80.8 MMBoe. During 2015, 8.1 MMBoe, or 10.0% of our December 31, 2014 proved undeveloped reserves (35 wells), were converted into proved developed reserves and required $165.3 million of drilling and completion capital and $5.0 million of facilities capital. These wells produced 0.9 MMBoe in 2015. During 2015, we added 2.6 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. Positive engineering revisions increased proved undeveloped reserves by 1.3 MMBoe. During 2015, 14.7 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 12.2 MMBoe of proved undeveloped reserves sold in the divestiture of our non-core DJ and Uinta Basin properties. Negative pricing revisions decreased proved undeveloped reserves by 18.0 MMBoe. The proved undeveloped reserves from December 31, 2014 that remained in the proved undeveloped reserves category at December 31, 2015 were 40.8 MMBoe.

At December 31, 2014, our proved undeveloped reserves were 80.8 MMBoe. At December 31, 2013, our proved undeveloped reserves were 113.7 MMBoe. During 2014, 10.2 MMBoe, or 9.0% of our December 31, 2013 proved undeveloped reserves (65 wells), were converted into proved developed reserves and required $227.5 million of drilling and completion capital and $9.5 million of facilities capital. These wells produced 0.9 MMBoe in 2014. During 2014, we added 12.5 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. During 2014, 36.6 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 27.7 MMBoe of proved undeveloped reserves sold in the divestiture of our Piceance and Powder River Basin properties. Negative engineering and pricing revisions decreased proved undeveloped reserves by 6.0 MMBoe. In addition, we added 7.4 MMBoe of proved undeveloped reserves as a result of acquired property in the DJ Basin. The proved undeveloped reserves from December 31, 2013 that remained in the proved undeveloped reserves category at December 31, 2014 were 66.8 MMBoe.

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.

We use our internal reserves estimates rather than the estimates of an independent third party engineering firm because we believe that our reservoir 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 third party engineers. We use our internal reserves estimates on all properties regardless of the positive or negative variance relative to the estimates of 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 third party engineers. We investigate any such differences and discuss the differences with the third party engineers to confirm that we used the proper methodologies and techniques in estimating reserves for the relevant field. These variances also are reviewed with our Reserves and EHS Committee. These differences are not resolved to a specified tolerance at the field or property level. In the aggregate, the 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, include but are 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 is intended to ensure the accuracy of the production data, which supplies the basis for forecasting.

12


A comparison is made and documented of land and lease record to interest data in the reserve database. This is intended to ensure 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 is intended to ensure 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 prices 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 designed 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 engineers. Discrepancies are discussed and differences are jointly resolved.
Internal reserves estimates are reviewed by well and by area by the Vice President of Reservoir and Planning. A variance by well to the previous year-end reserve report is used in this process. This review is independent of the reserves estimation process.
Reserves variances are discussed among the internal reservoir engineers and the Vice President of Reservoir and Planning. Our internal reserves estimates are reviewed by senior management and the Reserves and EHS Committee prior to publication.

Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is William K. Stenzel. Mr. Stenzel is our Vice President of Engineering and Planning and became responsible for our reserves estimates starting in September 2014. Mr. Stenzel earned a Bachelor of Science degree in Civil Engineering from Colorado State University in 1977. Mr. Stenzel has over 38 years of experience in reserves and economic evaluations, as well as a broad experience in production, completions, reservoir analysis and planning and development.

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, a Licensed Professional Engineer in the State of Texas (No. 49093), has been practicing consulting petroleum engineering at NSAI since 1980 and has over 7 years of prior industry experience. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience. 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 of 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 at 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.

13


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 may 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 analogy to other wells in the basin drilled on varying well spacing.
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 and compare to basin analogs.
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 at 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 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 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 2015 and 2014, we paid NSAI approximately $200,000 and $400,000, 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:


14


 
Year Ended December 31,
2015
 
2014
 
2013
Company Production Data:
 
 
 
 
 
Oil (MBbls)
4,401

 
4,012

 
3,495

Natural gas (MMcf)
7,764

 
21,744

 
52,685

NGLs (MBbls)
898

 
1,476

 
2,199

Combined volumes (MBoe)
6,593

 
9,112

 
14,475

Daily combined volumes (Boe/d)
18,063

 
24,964

 
39,658

DJ Basin – Production Data (1):
 
 
 
 
 
Oil (MBbls)
2,958

 
1,682

 
757

Natural gas (MMcf)
6,012

 
4,224

 
2,016

NGLs (MBbls)
815

 
423

 
195

Combined volumes (MBoe)
4,775

 
2,809

 
1,288

Daily combined volumes (Boe/d)
13,082

 
7,696

 
3,529

Uinta Oil Program – Production Data (1):
 
 
 
 
 
Oil (MBbls)
1,420

 
1,821

 
1,996

Natural gas (MMcf)
1,728

 
2,220

 
3,024

NGLs (MBbls)
82

 
119

 
142

Combined volumes (MBoe)
1,790

 
2,310

 
2,642

Daily combined volumes (Boe/d)
4,904

 
6,329

 
7,238

Piceance – Gibson Gulch Production Data (1)(2):
 
 
 
 
 
Oil (MBbls)

 
177

 
331

Natural gas (MMcf)

 
14,808

 
25,470

NGLs (MBbls)

 
911

 
1,858

Combined volumes (MBoe)

 
3,556

 
6,434

Daily combined volumes (Boe/d)

 
9,742

 
17,627

Average Costs ($ per Boe):
 
 
 
 
 
Lease operating expense
$
6.48

 
$
6.62

 
$
4.85

Gathering, transportation and processing expense (3)
0.53

 
3.89

 
4.65

Total production costs excluding production taxes
$
7.01

 
$
10.51

 
$
9.50

Production tax expense
1.85

 
3.44

 
1.88

Depreciation, depletion and amortization
31.14

 
25.88

 
19.33

General and administrative (4)
6.53

 
4.61

 
3.39


(1)
The DJ Basin and the Uinta Oil Program in the Uinta Basin were the only development areas that contained 15% or more of our total proved reserves as of December 31, 2015 and December 31, 2014. 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.
(2)
On September 30, 2014, the Company completed the sale of its Gibson Gulch natural gas program in the Piceance Basin (the "Piceance Divestiture"). As a result, the production and cost data related to the Piceance Basin as reported above includes values through the closing date of September 30, 2014. See Note 4 to the Consolidated Financial Statements for more information related to this divestiture.
(3)
During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. Beginning October 1, 2014, and as a result of the previous divestitures of the associated gas assets, these transportation costs were excluded from gathering, transportation and processing expense and included in unused commitments expense in the Consolidated Statements of Operations.

15


(4)
General and administrative expense presented herein excludes long-term cash and equity incentive compensation of $10.8 million, $11.4 million and $15.8 million for the years ended December 31, 2015, 2014 and 2013, respectively. If included, these long-term cash and equity incentive compensation expenses would have increased general and administrative expense by $1.64, $1.25 and $1.09 per Boe for the years ended December 31, 2015, 2014 and 2013, respectively. General and administrative expense excluding long-term cash and equity incentive compensation is a non-GAAP measure. Long-term cash and equity incentive compensation is combined with general and administrative expense for a total of $53.9 million, $53.4 million and $64.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, in the Consolidated Statements of Operations. Management believes the separate presentation of long-term cash and equity incentive compensation from general and administrative expense allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with cash performance compensation programs and stock-based grants.

Productive Wells

The following table sets forth information at December 31, 2015 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/Area
 
Gross Wells
 
Net Wells
 
Gross Wells
 
Net Wells
DJ
 
233.0

 
136.0

 
47.0

 
27.3

Uinta Oil Program
 
238.0

 
145.1

 
4.0

 
0.8

Other
 
11.0

 
4.9

 
3.0

 
0.6

Total
 
482.0

 
286.0

 
54.0

 
28.7


Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2015 relating to our leasehold acreage.

 
 
Developed Acreage (1)
 
Undeveloped Acreage (2)
 
Basin/Area
 
Gross
 
Net
 
Gross
 
Net
 
DJ
 
35,414

 
25,653

 
64,957

 
33,796

 
Uinta Oil Program
 
67,193

 
40,293

 
79,920

 
31,283

(3) 
Other
 
5,550

 
4,782

 
318,619

 
213,390

(4) 
Total
 
108,157

 
70,728

 
463,496

 
278,469



(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)
The Uinta Oil Program does not include an additional 126,625 gross and 51,806 net undeveloped acres that are subject to drill-to-earn agreements.
(4)
Other includes 107,171 and 63,367 net undeveloped acres in the Paradox and Deseret Basins, respectively.

Substantially all 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 periods 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, 2015, the expiration periods of the net undeveloped acres by area that are subject to leases summarized in the above table of undeveloped acreage.


16


 
 
Net Undeveloped Acres Expiring
Basin/Area
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
Total
DJ
 
13,012

 
5,267

 
2,157

 
2,081

 
11,279

 
33,796

Uinta Oil Program
 
5,490

 
8,544

 
4,482

 
506

 
12,261

 
31,283

Paradox
 
20,452

 
21,317

 
14,147

 

 
51,255

 
107,171

Deseret
 

 

 
39,909

 
21,245

 
2,213

 
63,367

Other
 
7,740

 
7,238

 
573

 
33

 
27,268

 
42,852

Total
 
46,694

 
42,366

 
61,268

 
23,865

 
104,276

 
278,469


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 or value of reserves found. 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 sufficiently exceed production expenses and taxes to justify completion of the well.

 
Year Ended December 31,
 
2015
 
2014
 
2013
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development
 
 
 
 
 
 
 
 
 
 
 
Productive
82.0

 
50.4

 
94.0

 
72.7

 
164.0

 
85.8

Dry
1.0

 
0.9

 

 

 

 

Exploratory
 
 
 
 
 
 
 
 
 
 
 
Productive

 

 

 

 

 

Dry

 

 

 

 

 

Total
 
 
 
 
 
 
 
 
 
 
 
Productive
82.0

 
50.4

 
94.0

 
72.7

 
164.0

 
85.8

Dry
1.0

 
0.9

 

 

 

 


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 construct, operate and maintain gas gathering facilities associated with our operations. 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 all of the oil production from our operated properties. Our natural gas and related NGLs are generally marketed by third parties under percentage of proceeds ("POP") 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, refineries, marketing 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 or results of operations as there are competitive markets available.


17


During 2015, two customers accounted for 44% of our oil and gas production revenues. During 2014, four customers accounted for 52% of our oil and gas production revenues. During 2013, five customers accounted for 49% of our oil and gas production revenues.

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

Our 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 off of either 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 natural gas pipeline transportation contracts, which entail a demand charge for reservation of capacity. These contracts were initiated to provide a guaranteed outlet for company marketed production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Accordingly, we will continue to incur monthly demand charges of approximately $1.5 million for the remaining term of six years even though we no longer utilize these contracts. These transportation costs are included in unused commitments expense in the Consolidated Statements of Operations.

Type of Arrangement
 
Pipeline System / Location
 
Deliverable Market
 
Gross Deliveries (MMBtu/d)
 
Term
Firm Transport
 
Questar Overthrust
 
Rocky Mountains
 
50,000
 
08/11 – 07/21
Firm Transport
 
Ruby Pipeline
 
West Coast
 
50,000
 
08/11 – 07/21

Hedging Activities

Our hedging program is intended to mitigate the risks of volatile prices of oil, natural gas, and NGLs. We currently have hedged 2,478,600 barrels of oil and 1,830,000 MMbtu of natural gas or approximately 50% of our expected 2016 production and 683,250 barrels of oil for our 2017 production at price levels that provide some economic certainty to our cash flows. To date eight of our 13 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 may be 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 may have a greater ability to continue exploration activities during periods of low oil, natural gas and NGLs market prices. Our larger or integrated competitors may be 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, and this 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 typically conduct a 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 such 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.

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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 NGL producing properties are subject to customary royalty and other interests, liens for current taxes, liens under our credit facility and other burdens that we believe do not materially interfere with the use of our properties.

Environmental Matters and Regulation

General. Our operations are subject to comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment, management of E&P waste, or otherwise relating to environmental protection and minimization of aesthetic impacts. Our operations are generally 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 effective emission control equipment;     
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;     
limit or prohibit drilling activities on lands lying within environmentally sensitive areas, wilderness, wetlands and other protected areas, including areas proximate to residential areas and certain high-occupancy buildings;
require measures to prevent pollution from current operations, such as E&P 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, for example, by limiting the flaring of associated natural gas from an oil well while awaiting a pipeline connection. 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 are, and have historically been, in substantial compliance 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 extraordinary. We believe that our compliance with existing requirements has 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. For the year ended December 31, 2015, we did not incur any material capital expenditures for remediation of well sites or production facilities or to retrofit emission 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

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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. In addition, certain environmental groups have petitioned the EPA 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 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" (generally excluding petroleum) 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 water, stormwater drainage 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 laws also prohibit the discharge of dredge and fill material in regulated waters, including jurisdictional wetlands, unless authorized under a permit issued by the U.S. Army Corps of Engineers ("Corps"). Federal and state regulatory agencies can impose administrative penalties, civil and criminal penalties, and take judicial action for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. The EPA and the Corps finalized a federal rulemaking to revise the jurisdictional definition of "Waters of the United States" in June 2015. The final rule currently is stayed and not effective pending ongoing litigation. The final rule, when effective, may expand the definition of "Waters of the United States" to include certain waters, including wetlands and tributaries not currently regulated. This definition would subject certain activities in those waters to permitting under the Clean Water Act, including permitting under Section 404 of the Clean Water Act for various activities, including wetlands development. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs may also limit the total volume of water or fill material 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, emission reporting, and the imposition of emission control requirements. Most of our facilities are now required to obtain permits before work can begin, and existing facilities are often required to incur additional capital costs in order to maintain compliance with laws and regulations. In 2012, the EPA issued new New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) specific to the oil and gas industry, including air standards for natural gas wells that are hydraulically fractured, and has issued several

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amendments to the NSPS rules in 2013 and 2014, respectively. In addition, the EPA has deemed carbon dioxide ("CO2") and other greenhouse gases, including methane, to be a danger to public health, which is leading to regulation of greenhouse gases in a manner similar to other pollutants. For example, the EPA proposed new regulations focused on methane emissions from the oil and gas industry in Fall 2015. A final rule is expected in 2016. The Bureau of Land Management also has proposed similar methane and gas-capture rules for oil and gas operations on federal and tribal leases. The EPA already requires reporting of greenhouse gases, such as CO2 and methane, from operations. In February 2014, Colorado expanded its oil and gas air regulations, including the adoption of the first set of fugitive methane emission control regulations in the United States and the EPA and the State of Utah currently are examining additional air quality regulations that might affect our Uinta Basin operations. In addition, the EPA has lowered the national ambient air quality standard for ozone pollution, which may require the oil and gas industry to further reduce emissions of volatile organic compounds and nitrogen oxides. Further, Colorado's ozone non-attainment status was bumped-up from "marginal" to "moderate," which triggers significant additional obligations for the State under the Clean Air Act. 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.

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, as well as local, state and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into prospective rock formations at depth to stimulate oil and natural gas production. We use this completion technique on substantially all of our wells to obtain commercial production.

Under the direction of Congress, the EPA has undertaken a study of the effect, if any, of hydraulic fracturing on drinking water and groundwater and released its report in 2015, finding no systematic impact on groundwater resources. In April 2015, EPA has also published proposed 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 or the Toxic Substances Control 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 already issued such 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 and in 2015, EPA granted, in part, one of these petitions to add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under the Toxic Release Inventory. In addition, the Department of the Interior finalized expanded or new regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes some of the lands on which we conduct or plan to conduct operations. These regulations have been stayed pending ongoing litigation. In Colorado, certain local jurisdictions have imposed moratoria or bans on hydraulic fracturing, several of which have been invalidated in court, but are now on appeal. In 2014, a citizen initiative that would have empowered local governments to ban hydraulic fracturing was certified for the November ballot. Another initiative would have imposed a statewide 2,000 foot drilling setback to homes or other occupied buildings. These initiatives were withdrawn from the ballot under an arrangement between Colorado Governor Hickenlooper and Congressman Polis, a financial supporter of these initiatives, which entailed the appointment of a Task Force to consider legislative and regulatory measures to address the concerns underlying the initiative effort. The recommendations of this Task Force and resulting rules recently finalized may impact our operations, but have not deterred additional attempts to restrict drilling or hydraulic fracturing. Several ballot initiatives have been filed for the next election cycle. Opponents of hydraulic fracturing received encouragement when New York banned the practice for the foreseeable future. Should measures restricting or banning the practice of hydraulic fracturing succeed in Colorado, the impact on the Company and the industry in general would be severe, and could force us to seek other basins in which to operate. The Company participates in industry organizations that have mobilized to combat such measures.

Climate Change. In June 2014, the U.S. Supreme Court upheld a portion of the EPA's greenhouse gas regulatory program for certain major sources in the Utility Air Regulatory Group v. EPA case. The EPA has finalized significant new rules to curb carbon emissions from power plants and other industrial activities, known as the Clean Power Plan, which in February 2016 was stayed by the U.S. Supreme Court. In addition, certain environmental groups are agitating for scaling back, or eliminating, fossil fuel extraction and use, including efforts to convince policy-makers that the majority of known oil and gas reserves must never leave the ground. These groups are mobilizing around a movement for global divestment from fossil fuel companies, which, if effective, could affect the market for our securities. In addition, in December 2015 the United States reached agreement during the United Nations climate change conference in Paris to make a 26-28% reduction in its greenhouse gas emissions by 2025 against a 2005 baseline. Potential future laws or regulations addressing greenhouse gas emissions could impact our business by limiting emissions of methane, restricting the flaring or venting of natural gas, or by reducing demand for oil or natural gas.

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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

Our operations are subject to other types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, bonds securing plugging, abandonment and reclamation obligations, and reports concerning our 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 noise, traffic and light from the location;
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;
wildlife management and protection;
the protection of archeological and paleontological resources;
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 well density and location, as well as the pooling of oil and natural gas properties. Some states provide statutory mechanisms for compulsory pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, compulsory pooling or unitization may be implemented by third parties and subject our interest to third party operations. While not currently an issue in Colorado or Utah, other states establish maximum rates of production from oil and natural gas wells and impose requirements regarding ratable takes by purchasers of production. Such laws and regulations, if adopted in Colorado or Utah, might 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, our production is generally subject to multiple layers of severance and/or ad valorem taxation by states, counties and tribes.

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 "first sales" of domestic natural gas, 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 pursued by FERC and Congress over the past few decades 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.

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 Office of Natural Resources Revenue, 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

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matters.

Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and BLM. 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 February 2, 2016, we had 139 employees of whom 93 work in our Denver office and 46 work in our field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.

Offices

As of December 31, 2015, 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 Greeley, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

Annual CEO Certification

As required by New York Stock Exchange rules, on May 20, 2015, 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

Oil and gas prices are volatile and a continued 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 for oil, natural gas and NGLs. The markets for these commodities are very volatile, based on supply and demand, 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;

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domestic and foreign governmental regulations;
variations between product prices at sales points and applicable index prices;
political and economic conditions in oil producing countries, including the Middle East and South America;
the ability and willingness 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;
national and global economic conditions;
proximity and capacity of oil and gas pipelines, refineries and other transportation and processing facilities;
the price and availability of alternative fuels; and
the strength of the U.S. dollar compared to other currencies.

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 and the estimated value of future cash flows from our reserves. This may result in our having to make substantial downward adjustments to the estimated quantity and value of our 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 or impair, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. 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 recorded impairment charges of $572.4 million in the year ended December 31, 2015 on our proved and unproved oil and gas properties, and may record similar charges in the future.

Oil prices declined severely beginning in 2014, and price decreases continued through 2015 and into 2016. Natural gas and NGL prices have experienced decreases of comparable magnitude over the same period. These decreases have increased the volatility and amplitude of the other risks facing us as described in this report and has impacted our unit price and is having an impact on our business and financial condition. If oil prices remain at current levels or lower, our planned drilling projects may become uneconomic, which could affect future drilling plans and growth rates. Low commodity prices impact our revenue, which we partially mitigate with our hedging program. Continued low commodity prices make it more challenging to hedge production at higher price levels. At December 31, 2015, we had hedged a total of 3,161,850 barrels of oil for 2016 and 2017 and 1,830,000 MMbtu of natural gas for 2016. These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices, and we currently have less production covered by hedges than we have had in recent periods. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and this would negatively impact our results of operations and financial condition.

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

We have acquired significant amounts of proved and 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 proved and 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 proved or 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 proved or 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. In addition, even a commercial well may have production that is less, or costs that are greater than, we projected. 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 results in our plays may be more uncertain than in other plays that are more mature and have longer established drilling and

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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.

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

Our operations are 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 contaminated soil and groundwater, protection of surface and groundwater, land reclamation and preservation of natural resources. In addition, a portion of our leases in the Uinta Basin are regulated by tribal authorities. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, permit, 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, leading to delays.

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 high paraffin content which limits the number of refiners able to purchase it as feedstock. 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 under-insured 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:


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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;
abnormally pressured or structured formations;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
fires, explosions and ruptures of pipelines;
personal injuries and death; and
natural disasters.

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

injury or loss of life;
damage to and destruction of property and equipment;
damage to natural resources due to underground migration of hydraulic fracturing fluids or other fluids or gases;
pollution and other environmental damage, including spillage or mishandling of recovered hydrocarbons, 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. Further, we could be unaware of a pollution event when it occurs and therefore be unable to report the event within the time period required under the relevant policy. 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 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. 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. Recent commodity price decreases have made it substantially more difficult for us and other industry participants to raise capital, and will likely have an adverse effect on our borrowing base.

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.


26


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.

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, 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 willingness and 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 13 lenders. If credit markets become turbulent as a result of an economic downturn, delayed economic recovery, lower commodity prices or other factors, our lenders may become more restrictive in their lending practices or may be unwilling or unable to fund their commitments, which would limit our access to capital to fund our capital expenditures, operations or meet other obligations. 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 if, as a result of a crisis in the global financial and securities markets, a deterioration in national or global growth prospects or other factors, an economic downturn occurs:

The economic slowdown could lead to lower demand for oil and natural gas by individuals and industries, which in turn could result in lower prices for the oil and natural gas sold by us, lower revenues and possibly losses. Significant recent commodity price declines have been caused in part by concerns about future global economic growth. This factor has been exacerbated by increases in oil and gas supply resulting from increases in U.S. oil and 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

27


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 ("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. In addition, the lenders can request an interim redetermination during each six month period which could reduce the funds available to borrow under our credit facility.

Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash and 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.

At December 31, 2015, approximately 52% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $619.3 million during the five years ending December 31, 2020. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC's reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame.

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.


28


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.

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;
our production is less than we expect;
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 Protection Act ("Dodd-Frank") was signed into law in July 2010. Dodd-Frank regulates derivative transactions, including our commodity derivative swaps. We expect that Dodd-Frank and its implementing regulations will increase the cost to hedge as a result of fewer counterparties being in the market and the pass-through of increased capital costs of bank subsidiaries. The imposition of margin requirements or other restrictions on our hedging activities could make hedging more expensive or impracticable. A reduction in 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, and/or an extended period of low commodity prices would increase these risks.

We face risks related to rating agency downgrades.
        
If one or more rating agencies downgrades our outstanding debt, future debt issuance could become more difficult and more costly. Also, we may be required to provide collateral or other credit support to certain counterparties, which would increase our costs and limit our liquidity.

29



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, acquire cash or other assets through theft or fraud or 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, corruption of data or misappropriation of assets. There can be no assurance that the procedures and controls we use to monitor and mitigate these risks 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, assets, 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

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.

These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions that are opposed by our board. 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, and this 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 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. In particular, these risks have been significantly exacerbated by continuing weakness in commodity prices.

As of December 31, 2015, the total outstanding principal amount of our indebtedness was approximately $803.8 million, and we had approximately $349.0 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, 2015, $375.0 million based on our June 30, 2015 proved reserves and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. As of December 31, 2015, we had no amounts outstanding under our Amended Credit Facility.


30


The borrowing base is set at the sole discretion of the lenders. Our next scheduled borrowing base redetermination is scheduled on or about April 1, 2016 based on proved reserves as of December 31, 2015 at updated bank price decks and hedge position. However, in the event of lower capital investment in our properties due to a sustained cycle of low commodity prices, we could see lower quantities of proved developed reserves which would, in combination with lower oil and gas commodity pricing, lead to lower borrowing bases.

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 be completed in a timely manner or at all, and even if completed may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Our debt could have important consequences. For example, it could:
    
increase our vulnerability to general adverse economic and industry conditions;
limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
impair our ability to obtain additional financing in the future; and
place us at a competitive disadvantage compared to our competitors that have less debt.

The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on the 2016 budget. However, if commodity prices continue at current levels or lower, EBITDAX will be significantly reduced, which is a critical underpinning of our required financial covenants. If this were to occur, it will make it necessary for us to negotiate an amendment to one or more of these financial covenants.

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. In September 2015, we obtained an amendment to the Amended Credit Facility that replaced our debt-to-EBITDAX covenant in the facility for a limited period of time. Through March 31, 2018, the covenants are secured debt-to-EBITDAX and EBITDAX-to-interest. There can be no assurance that we will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.

We may not be able to meet future debt obligations or debt service costs on our outstanding debt instruments in the event of a sustained down cycle in commodity prices.

Volatile oil, natural gas and NGLs prices can have a significant effect on our revenue, profitability and cash flows from operations. Even relatively modest declines in prices can significantly affect our financial results and impede our ability to meet existing debt obligations undertaken to finance the substantial capital required to successfully explore and produce economically viable oil and natural gas properties. Sustained low commodity prices of the nature we are currently experiencing may not allow us to generate sufficient cash flows to cover debt obligations in the future (our principal debt obligations become due starting in 2019) and/or debt service charges in the near term.

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

31


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 and their evaluation of business conditions. 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. A breach of any covenant would also limit the funds available under our Amended Credit Facility.

Risks Related to Tax

We may incur more taxes 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 or if additional taxes are imposed on us.
 
The Administration of President Obama and the Democratic party in general 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.
 
In addition, the President has recently proposed a new tax on energy companies of $10.25 per barrel of oil. 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.

Our utilization of net operating loss carryforwards may be limited based on current Internal Revenue Code restrictions

The Company has significant net operating loss ("NOL") carryforwards. Subject to certain limitations and applicable expiration dates, these tax attributes can be carried forward to reduce the Company's federal income tax liability for future periods. Under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), the Company's NOL carryforwards would become subject to the "section 382 limitation" if the Company were to experience an "ownership change." For this purpose, the term "ownership change" refers to an increase in ownership of at least 50% of the Company's shares by certain groups of shareholders during any three-year period, as determined under certain conventions. As of December 31, 2015, the Company believes it has not experienced an ownership change under Section 382.

If the Company were to undergo an ownership change at any time under Section 382 of the Code, the Company's NOL carryforwards could only be used to offset an amount of income equal to the "section 382 limitation" in each taxable year. Any NOL carryforwards that could not be used as a result of the section 382 limitation would carry forward to future years, still subject to the same section 382 limitation, unless and until they expire unused. The Company's "section 382 limitation" would generally equal the fair market value of the Company's outstanding equity (as of the date of the ownership change) multiplied

32


by a certain interest rate (as of the date of the ownership change) published monthly by the U.S. Treasury Department and known as the "long-term tax exempt rate."

The Company expects to have sufficient income to utilize its alternative minimum tax credit, which may be carried forward indefinitely.

In addition, if an ownership change were to incur in the future, the Company could be required to write off a significant portion of the deferred tax asset related to our NOL carryforwards in accordance with GAAP.

Item 1B. Unresolved Staff Comments.

None.

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.

We have received an EPA "Section 114" mandatory information directive, usually a precursor to an enforcement proceeding. We have also received parallel "compliance advisories" from the Colorado Department of Public Health and Environment.

Item 4. Mine Safety Disclosures.

Not applicable.


33


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
2015
 
 
 
First Quarter
$
13.36

 
$
7.90

Second Quarter
11.72

 
7.44

Third Quarter
8.64

 
2.75

Fourth Quarter
7.04

 
3.30

2014
 
 
 
First Quarter
$
29.73

 
$
21.85

Second Quarter
29.35

 
21.50

Third Quarter
27.39

 
20.59

Fourth Quarter
22.51

 
7.54


On February 2, 2016, the closing sales price for our common stock as reported by the NYSE was $3.30 per share.

Holders. On February 2, 2016, the number of holders of record of our common stock was 106.

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 debt agreements limit 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, 2015.

Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2015:

Period
 
Total
Number of
Shares Purchased (1)
 
Weighted
Average Price
Paid Per
Share
 
Total Number of Shares
Purchased as
Part of Publicly
Announced Plans or
Programs
 
Maximum Number (or
Approximate Dollar Value)
of Shares that
May Yet be Purchased
Under the Plans or
Programs
October 1 - 31, 2015
 
679

 
$
5.14

 
0

 
0

November 1 - 30, 2015
 
10,043

 
$
6.27

 
0

 
0

December 1 - 31, 2015
 
1,558

 
$
4.38

 
0

 
0

Total
 
12,280

 
$
5.96

 
0

 
0


(1)
Represents 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


34


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, 2010, and $100 was invested in each of the Standard & Poors MidCap 400 Index-Energy Sector and the Standard & Poors 500 Index at the closing price on December 31, 2010.

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


 
December 31,
2010
 
December 31,
2011
 
December 31,
2012
 
December 31,
2013
 
December 31,
2014
 
December 31,
2015
BBG
$
100

 
$
83

 
$
43

 
$
66

 
$
28

 
$
10

S&P MidCap 400- Energy
100

 
90

 
88

 
111

 
82

 
54

S&P 500
100

 
100

 
113

 
147

 
164

 
163


Item 6. Selected Financial Data.

The following table presents our selected historical financial data for the years ended December 31, 2015, 2014, 2013, 2012 and 2011. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines, properties acquired or sold 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, 2015, 2014 and 2013 and the balance sheet information as of December 31, 2015 and 2014 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, 2012 and 2011 and the balance sheet information at December 31, 2013, 2012 and 2011 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.


35


 
Year Ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
(in thousands, except per share data)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Operating and Other Revenues:
 
 
 
 
 
 
 
 
 
Oil, gas and NGL production (1)
$
204,537

 
$
464,137

 
$
565,555

 
$
700,639

 
$
780,751

Other
3,355

 
8,154

 
2,538

 
(444
)
 
4,873

Total operating and other revenues
207,892

 
472,291

 
568,093

 
700,195

 
785,624

Operating Expenses:
 
 
 
 
 
 
 
 
 
Lease operating expense
42,753

 
60,308

 
70,217

 
72,734

 
56,603

Gathering, transportation and processing expense
3,482

 
35,437

 
67,269

 
106,548

 
93,423

Production tax expense
12,197

 
31,333

 
27,172

 
25,513

 
37,498

Exploration expense
153

 
453

 
337

 
8,814

 
3,645

Impairment, dry hole costs and abandonment expense
575,310

 
46,881

 
238,398

 
67,869

 
117,599

(Gain) loss on divestitures
1,745

 
100,407

 

 

 

Depreciation, depletion and amortization expense
205,275

 
235,805

 
279,775

 
326,842

 
288,421

Unused commitments
19,099

 
4,434

 

 

 

General and administrative expense (2)
43,050

 
41,981

 
49,069

 
52,222

 
47,744

Long-term cash and equity incentive compensation (2)
10,840

 
11,380

 
15,833

 
16,444

 
19,036

Total operating expenses
913,904

 
568,419

 
748,070

 
676,986

 
663,969

Operating Income (Loss)
(706,012
)
 
(96,128
)
 
(179,977
)
 
23,209

 
121,655

Other Income and Expense:
 
 
 
 
 
 
 
 
 
Interest income and other income (expense)
565

 
1,294

 
1,646

 
155

 
(397
)
Interest expense
(65,305
)
 
(69,623
)
 
(88,507
)
 
(95,506
)
 
(58,616
)
Commodity derivative gain (loss)
104,147

 
197,447

 
(23,068
)
 
72,759

 
(14,263
)
Gain (loss) on extinguishment of debt
1,749

 

 
(21,460
)
 
1,601

 

Total other income and expense
41,156

 
129,118

 
(131,389
)
 
(20,991
)
 
(73,276
)
Income (Loss) before Income Taxes
(664,856
)
 
32,990

 
(311,366
)
 
2,218

 
48,379

(Provision for) Benefit from Income Taxes
177,085

 
(17,909
)
 
118,633

 
(1,636
)
 
(17,672
)
Net Income (Loss)
$
(487,771
)
 
$
15,081

 
$
(192,733
)
 
$
582

 
$
30,707

Net Income (Loss) per Common Share:
 
 
 
 
 
 
 
 
 
Basic
$
(10.10
)
 
$
0.31

 
$
(4.06
)
 
$
0.01

 
$
0.66

Diluted
$
(10.10
)
 
$
0.31

 
$
(4.06
)
 
$
0.01

 
$
0.65

Weighted average common shares outstanding, basic
48,303.3

 
48,010.7

 
47,496.9

 
47,194.7

 
46,535.6

Weighted average common shares outstanding, diluted
48,303.3

 
48,435.7

 
47,496.9

 
47,354.0

 
47,236.7



36


 
Year Ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
(in thousands)
Selected Cash Flow and Other Financial Data:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(487,771
)
 
$
15,081

 
$
(192,733
)
 
$
582

 
$
30,707

Depreciation, depletion, impairment and amortization
777,713

 
275,988

 
506,326

 
364,190

 
388,699

Other non-cash items
(83,760
)
 
(59,970
)
 
(32,600
)
 
29,281

 
55,102

Change in assets and liabilities
(12,504
)
 
30,618

 
(15,728
)
 
(5,617
)
 
4,840

Net cash provided by operating activities
$
193,678

 
$
261,717

 
$
265,265

 
$
388,436

 
$
479,348

Capital expenditures (3)(4)(5)
$
287,411

 
$
569,312

 
$
474,031

 
$
962,573

 
$
987,341


(1)
The oil, gas and NGL production revenue decrease reflects the decrease in revenues due to the divestitures outlined in Note 4 to the Consolidated Financial Statements and the decrease in commodity price. In addition, oil, gas and NGL production revenues include the effects of cash flow hedging transactions for the years ended December 31, 2014, 2013, 2012 and 2011. We discontinued hedge accounting effective January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in accumulated other comprehensive income ("AOCI") effective January 1, 2012 and remained in AOCI until the underlying transaction occurred. As the underlying transaction occurred, these gains or losses were reclassified from AOCI into oil and gas production revenues.
(2)
Long-term cash and equity incentive 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 $53.9 million, $53.4 million, $64.9 million, $68.7 million and $66.8 million for the years ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively. This separate presentation is a non-GAAP measure. Management believes the separate presentation of long-term cash and equity incentive compensation from general and administrative expense allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with cash performance compensation programs and stock-based grants.
(3)
Excludes future reclamation liabilities of negative $7.5 million, negative $8.6 million, negative $6.6 million, $7.5 million and $12.1 million for the years ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $3.0 million, $7.2 million, $12.2 million, $39.3 million and $21.0 million for the years ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively. Also includes furniture, fixtures and equipment costs of $1.3 million, $3.7 million, $1.3 million, $6.9 million and $8.9 million for the years ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively.
(4)
Not deducted from the amount are $123.3 million, $555.4 million, $306.3 million, $325.3 million and $2.0 million of proceeds received principally from the sale of interests in oil and gas properties during the years ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively.
(5)
Capital expenditures for the year ended December 31, 2014 exclude $79.0 million related to property acquired through property exchanges.


37


 
As of December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
(in thousands)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
128,836

 
$
165,904

 
$
54,595

 
$
79,445

 
$
57,331

Other current assets
145,481

 
260,201

 
102,652

 
148,894

 
189,012

Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment
1,160,898

 
1,730,172

 
2,184,183

 
2,584,979

 
2,383,196

Other property and equipment, net of depreciation
9,786

 
13,715

 
18,313

 
26,358

 
23,568

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

 
9,234

 

 

 

Other assets
70,228

 
65,258

 
21,770

 
29,773

 
34,823

Total assets
$
1,515,229

 
$
2,244,484

 
$
2,381,513

 
$
2,869,449

 
$
2,687,930

Current liabilities
$
145,231

 
$
264,687

 
$
192,719

 
$
213,133

 
$
233,198

Long-term debt
803,361

 
803,222

 
979,082

 
1,156,654

 
882,240

Other long-term liabilities
17,221

 
147,087

 
203,994

 
316,887

 
353,654

Stockholders' equity
549,416

 
1,029,488

 
1,005,718

 
1,182,775

 
1,218,838

Total liabilities and stockholders' equity
$
1,515,229

 
$
2,244,484

 
$
2,381,513

 
$
2,869,449

 
$
2,687,930


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

Introduction

The following discussion and analysis should be read in conjunction with the "Selected Financial Data" and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the "Cautionary Note Regarding Forward-Looking Statements" at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in "Items 1 and 2. Business and Properties - Business - Operations - Environmental Matters and Regulation;" "Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry;" and "Item 1A. Risk Factors" above, all of 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 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.

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.

Oil prices declined severely beginning in 2014, and price decreases continued through 2015 and into 2016. Natural gas and NGL prices have experienced decreases of comparable magnitude over the same period. These decreases have increased the volatility and amplitude of the other risks facing us as described in this report and have impacted our average realized unit price and are having an impact on our business and financial condition. Commodity prices are inherently volatile and are influenced by many factors outside of our control. Our activities and capital budget maintain flexibility using what we believe to be conservative sales price assumptions and our existing hedge position. If commodity prices continue at current levels or lower,

38


our capital availability, liquidity and profitability are likely to be adversely affected as current hedges are realized in 2016 and 2017.

As we go through 2016, our priority remains ensuring ample liquidity and protecting the strength of our balance sheet, and we will adjust our development plans as necessary to this end. We remain in close contact with the banks in our credit facility and are evaluating the increased risk that lenders may seek to reduce our borrowing base due to their exposure to the energy industry or for other reasons. Further, we continue to monitor debt, equity and hedging markets for opportunities to strengthen our liquidity position.

We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders expectations and regulatory requirements.

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.

Because of our growth through acquisitions and, more recently, development of our properties and sales of properties in 2013, 2014 and 2015, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not indicative of future results.

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

 
Year Ended December 31,
 
2015
 
2014
 
2013
Estimated net proved reserves (MMBoe)
83.7

 
122.3

 
197.0

Standardized measure (1) (in millions)
$
327.6

 
$
1,169.6

 
$
1,377.5


(1)
December 31, 2015 reserves were based on average prices of $50.28 WTI per Bbl of oil, $2.59 Henry Hub per Mcf of natural gas and $20.37 per Bbl of NGLs. December 31, 2014 reserves were based on average prices of $94.99 WTI for oil, $4.35 Henry Hub for natural gas and $39.65 for NGLs. December 31, 2013 reserves were based on average prices of $96.91 WTI for oil, $3.67 Henry Hub for natural gas and $39.75 NGLs.

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,
 
2015
 
2014
 
2013
Oil (per Bbl)
$
40.06

 
$
77.92

 
$
82.61

Natural gas (per Mcf)
2.23

 
4.78

 
3.96

NGLs (per Bbl)
12.16

 
31.55

 
27.02


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:


39


 
Year Ended December 31,
 
2015
 
2014
 
2013
Oil (per Bbl)
$
78.19

 
$
79.51

 
$
82.38

Natural gas (per Mcf)
3.75

 
4.45

 
4.16

NGLs (per Bbl)
12.16

 
31.51

 
28.31


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. We currently have hedged 2,478,600 barrels of oil and 1,830,000 MMbtu of natural gas or approximately 50% of our expected 2016 production and 683,250 barrels of oil for our 2017 production at price levels that provide some economic certainty to our cash flows. 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.

Results of Operations

Year Ended December 31, 2015 Compared with Year Ended December 31, 2014

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

40


 
 
Year Ended December 31,
 
Increase (Decrease)
2015
 
2014
 
Amount
 
Percent
($ in thousands, except per unit data)
Operating Results:
 
 
 
 
 
 
 
Operating and Other Revenues
 
 
 
 
 
 
 
Oil, gas and NGL production (1)
$
204,537

 
$
464,137

 
$
(259,600
)
 
(56
)%
Other
3,355

 
8,154

 
(4,799
)
 
(59
)%
Total operating and other revenues
$
207,892

 
$
472,291

 
$
(264,399
)
 
(56
)%
Operating Expenses
 
 
 
 
 
 
 
Lease operating expense
$
42,753

 
$
60,308

 
$
(17,555
)
 
(29
)%
Gathering, transportation and processing expense (2)
3,482

 
35,437

 
(31,955
)
 
*nm

Production tax expense
12,197

 
31,333

 
(19,136
)
 
(61
)%
Exploration expense
153

 
453

 
(300
)
 
(66
)%
Impairment, dry hole costs and abandonment expense
575,310

 
46,881

 
528,429

 
*nm

(Gain) loss on divestitures
1,745

 
100,407

 
(98,662
)
 
(98
)%
Depreciation, depletion and amortization
205,275

 
235,805

 
(30,530
)
 
(13
)%
Unused commitments (2)
19,099

 
4,434

 
14,665

 
*nm

General and administrative expense (3)
43,050

 
41,981

 
1,069

 
3
 %
Long-term cash and equity incentive compensation (3)
10,840

 
11,380

 
(540
)
 
(5
)%
Total operating expenses
$
913,904

 
$
568,419

 
$
345,485

 
61
 %
Production Data:
 
 
 
 
 
 
 
Oil (MBbls)
4,401

 
4,012

 
389

 
10
 %
Natural gas (MMcf)
7,764

 
21,744

 
(13,980
)
 
(64
)%
NGLs (MBbls)
898

 
1,476

 
(578
)
 
(39
)%
Combined volumes (MBoe)
6,593

 
9,112

 
(2,519
)
 
(28
)%
Daily combined volumes (Boe/d)
18,063

 
24,964

 
(6,901
)
 
(28
)%
Average Realized Prices before Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
40.06

 
$
77.92

 
$
(37.86
)
 
(49
)%
Natural gas (per Mcf)
2.23

 
4.78

 
(2.55
)
 
(53
)%
NGLs (per Bbl)
12.16

 
31.55

 
(19.39
)
 
(61
)%
Combined (per Boe)
31.02

 
50.82

 
(19.80
)
 
(39
)%
Average Realized Prices with Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
78.19

 
$
79.51

 
$
(1.32
)
 
(2
)%
Natural gas (per Mcf)
3.75

 
4.45

 
(0.70
)
 
(16
)%
NGLs (per Bbl)
12.16

 
31.51

 
(19.35
)
 
(61
)%
Combined (per Boe)
58.27

 
50.73

 
7.54

 
15
 %
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expense
$
6.48

 
$
6.62

 
$
(0.14
)
 
(2
)%
Gathering, transportation and processing expense (2)
0.53

 
3.89

 
(3.36
)
 
(86
)%
Production tax expense
1.85

 
3.44

 
(1.59
)
 
(46
)%
Depreciation, depletion and amortization
31.14

 
25.88

 
5.26

 
20
 %
General and administrative expense (4)
6.53

 
4.61

 
1.92

 
42
 %