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, 2017



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, smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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, 2017 was $227,638,124 (based on the closing price of $3.07 per share as of the last business day of the fiscal quarter ended June 30, 2017).

As of February 6, 2018, the registrant had 110,349,217 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 will be included in a future filing with the SEC within 120 days after December 31, 2017, and is incorporated by reference in this report.

Table of Contents

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 by converting gas volumes to barrels of oil equivalent using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

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.

Completion. Refers to 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.

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.

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 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.

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.

Table of Contents

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

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

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

Mcf. Thousand cubic feet of natural gas.

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

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

MMBtu. Million British thermal units.

MMcf. Million cubic feet of natural gas.

Mt. Belvieu. The 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. 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.

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

Proved developed reserves. Proved 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 - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Proved undeveloped reserves or PUD. 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

Table of Contents

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.

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.

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 economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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

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, (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 statements in this report, other than statements of historical fact, are forward-looking statements. 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 the 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 being less than estimated;


•	changes in the estimates of proved reserves;


•	availability of midstream and downstream markets to sell our products;


•	reductions in the borrowing base under our revolving bank credit facility (sometimes referred to as 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, anticipated events addressed in forward looking statements 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. 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, 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.

Table of Contents

PART I

Items 1 and 2. Business and Properties.

BUSINESS

General

Bill Barrett Corporation together with our wholly-owned subsidiaries ("the Company", "we", "our" or "us") is an independent energy company that develops, acquires and explores for oil and natural gas resources. All of our assets and operations are located in the Rocky Mountain region of the United States.

We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize 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 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 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 and 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 18^th Street, Suite 2300, Denver, Colorado 80202. We intend to disclose on our website any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K. This Annual Report on Form 10-K and our website contain information provided by other sources that we believe are reliable. We cannot assure you that the information obtained from other sources is accurate or complete. No information on our website is incorporated by reference herein or deemed to be part of this Annual Report on Form 10-K.

We operate in one industry segment, which is the exploration, development and production of oil and natural gas, and all operations are conducted in the United States. Consequently, we currently report a single reportable segment. See "Financial Statements" and the notes to our consolidated financial statements for financial information about this reportable segment.

Significant Business Developments

Pending Merger with Fifth Creek Operating Company, LLC

On December 4, 2017, the Company together with its wholly-owned subsidiaries entered into an Agreement and Plan of Merger (the "Merger Agreement") with Fifth Creek Operating Company, LLC ("Fifth Creek"), Red Rider Holdco, Inc. ("Holdco"), a wholly owned subsidiary of ours ("New Parent"), Rio Merger Sub, LLC, a direct wholly owned subsidiary of New Parent ("Rio Grande Merger Sub"), Rider Merger Sub, Inc., a direct wholly owned subsidiary of New Parent ("Parent Merger Sub"), and, for limited purposes set forth in the Merger Agreement, Fifth Creek Energy Company, LLC ("Holdings") and NGP Natural Resources XI, L.P. ("NGP"). Pursuant to the terms of the Merger Agreement, at the closing of the mergers contemplated by the Merger Agreement (collectively, the "Merger") (a) Parent Merger Sub will be merged with and into the Company, with the Company surviving the Merger, and (b) Rio Grande Merger Sub will be merged with and into Fifth Creek, with Fifth Creek surviving the Merger, as a result of which the Company and Fifth Creek will each become direct wholly owned subsidiaries of New Parent.

Table of Contents

Upon the closing of the Merger, each share of our common stock will be converted into the right to receive one share of New Parent common stock and Holdings will receive 100 million shares of New Parent common stock, subject to the terms of the Stockholders Agreement to be entered into upon closing of the Merger by and among New Parent, Holdings and, for limited purposes set forth in the Stockholders Agreement, NGP.

Fifth Creek is an exploration and production company focusing on the development of oil and gas reserves from the DJ Basin. Fifth Creek's properties include approximately 81,000 net acres in Weld County in the DJ Basin, substantially all of which are operated. The assets we will acquire in the Merger also include 62 producing standard-length lateral wells and seven producing extended-reach lateral wells. Under the Merger Agreement, Fifth Creek may incur up to a total of $54 million in indebtedness prior to the closing of the Merger.

The closing of the transaction is subject to the receipt of any required regulatory approvals, the approval of the Company's stockholders and the satisfaction of other customary closing conditions. The Company's stockholders are scheduled to vote on March 16, 2018 and the transaction is expected to close on or about March 19, 2018.

Equity Offering

In December 2017, we completed a public offering of our common stock, selling 23,205,529 shares at a price to the public of $5.00 per share. The sale included the purchase of 2,205,529 shares of common stock by the underwriters pursuant to their over-allotment option. Net proceeds from the sale, after deducting fees and estimated expenses, were approximately $110.8 million.

Debt Exchange and Consent Solicitations

On December 13, 2017, we entered into consent agreements with the holders of a majority of our 7.0% Senior Notes and 8.75% Senior Notes to amend each of the indentures governing the respective notes to, among other things, amend the defined term "Change of Control" in each of the indentures to provide that the Merger will not constitute a "Change of Control" under such indentures. The Company paid consent fees of $2.50 per $1,000 principal amount, or approximately $1.7 million, related to the 7.0% Senior Notes and 8.75% Senior Notes.

On December 15, 2017, we completed a debt exchange with a holder of the 7.0% Senior Notes due 2022 (the "2017 Debt Exchange"). The holder exchanged $50.0 million principal amount of 7.0% Senior Notes for 10,863,000 newly issued shares of our common stock. Immediately after consummation of the 2017 Debt Exchange, $350.0 million aggregate principal amount of the 7.0% Senior Notes remained outstanding.

Sale of Uinta Basin Assets

On December 29, 2017, the Company completed the sale of its remaining non-core assets in the Uinta Basin. The Company received $102.3 million in cash proceeds, before final closing adjustments. In addition to the cash proceeds, the Company recognized non-cash proceeds of $4.8 million related to relief from the Company's asset retirement obligation. We recognized a proved property impairment of $37.9 million related to the sale of these assets.

PROPERTIES

Overview

As of December 31, 2017, we have one key area of production: the Denver-Julesburg Basin ("DJ 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, 2017 - 85.8 MMBoe.


•	Producing wells - We had interests in 368 gross (245.2 net) producing wells as of December 31, 2017, and we serve as operator in 262 gross wells.


•	2017 net production - 6,235 MBoe.


•	Acreage - We held 30,858 net undeveloped and 38,702 net developed acres as of December 31, 2017.

Table of Contents


•	Capital expenditures - Our capital expenditures for 2017 were $251.5 million for participation in the drilling of 73 gross (57.8 net) wells, acquisition of leasehold acres and construction of gathering facilities.


•	As of December 31, 2017, we were drilling 2 gross (1 net) well, and we were waiting to complete 17 gross (14.5 net) wells within the DJ Basin.


•	Based on our proved reserves as of January 1, 2018, we have a 73% weighted average working interest in our producing wells in the DJ Basin.

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 69 gross (56.1 net) operated wells and placed 54 gross (44.0 net) operated wells on initial flowback in 2017. The Company had one rig operating at the beginning of 2017 and added an additional rig in July of 2017 for a total of two rigs for the remainder of the year. In 2017, we focused on drilling extended reach horizontal wells in the Niobrara formation across 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 acreage in the area.

Currently, we are utilizing two rigs in the DJ Basin; however, we expect to add a third rig after closing the Merger. We may elect to accelerate or delay drilling throughout 2018 as business conditions and operating results warrant. The 2018 operated drilling program will focus on drilling extended reach wells (9,200 foot laterals). In addition, we anticipate minimal participation in non-operated wells.

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 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 at each of December 31, 2017, 2016 and 2015 based on reserve reports prepared by us and audited by independent third party petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our reserve estimates independently audited, such an audit is required under our Amended Credit Facility. All of our proved reserves included in our reserve reports are located in North America. Netherland, Sewell & Associates, Inc. ("NSAI") audited all of our reserves estimates at December 31, 2017, 2016 and 2015. 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.

Table of Contents



	As of December 31,
Proved Reserves: ⁽¹⁾	2017	2016	2015
Proved Developed Reserves:
Oil (MMBbls)	17.4	21.8	27.2
Natural gas (Bcf)	74.5	47.5	45.2
NGLs (MMBbls)	11.7	6.7	5.1
Total proved developed reserves (MMBoe)	41.5	36.4	39.8
Proved Undeveloped Reserves:
Oil (MMBbls)	22.2	9.3	28.3
Natural gas (Bcf)	68.4	28.7	52.8
NGLs (MMBbls)	10.7	4.4	6.8
Total proved undeveloped reserves (MMBoe) ⁽²⁾	44.3	18.5	43.9
Total Proved Reserves (MMBoe) ⁽³⁾	85.8	54.9	83.7

(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 2017 for natural gas (Henry Hub price) and oil (WTI Cushing price), subject to certain adjustments, or $2.98 per MMBtu of natural gas and $51.34 per barrel of oil, respectively, without giving effect to hedging transactions. The average NGL price of $27.40 per barrel was based on 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.


(2)	Approximately 52%, 34% and 52% of our estimated proved reserves (by volume) were undeveloped for the years ended December 31, 2017, 2016 and 2015, respectively.


(3)	Total proved reserves have been reduced for the sale of non-core oil and gas properties in the amount of 11.2 MMBoe, 2.0 MMBoe and 16.1 MMBoe for the years ended December 31, 2017, 2016 and 2015, respectively.

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".

The following tables illustrate the history of our proved undeveloped reserves from December 31, 2015 through December 31, 2017:



	As of December 31,
Proved Undeveloped Reserves:	2017		2016		2015
	(MMBoe)
Beginning balance	18.5		43.9		80.8
Additions from drilling program ⁽¹⁾	31.7		8.4		2.6
Acquisitions	—		—		—
Engineering revisions ⁽¹⁾	10.8		(0.7	)	1.3
Price revisions	0.2		(0.3	)	(18.0	)
Converted to proved developed	(13.0	)	(8.5	)	(8.1	)
Sold/ expired/ other ⁽²⁾	(3.9	)	(24.3	)	(14.7	)
Total proved undeveloped reserves ⁽³⁾	44.3		18.5		43.9


(1)	The increase in proved undeveloped reserves is the result of our development activity level in 2017. The upward revisions include approximately 42.5 MMboe that were added to the proved undeveloped reserve category as these locations are included in our near-term development plans.


(2)	Approximately 3.9 MMboe of proved undeveloped reserves were removed as the planned development of these locations are outside the SEC's five-year development window, which is based on when the proved undeveloped location was added.


(3)	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 DJ Basin proved undeveloped locations constitute approximately two rig years' worth of drilling

Table of Contents

over the next three 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 more attractive rates of return, leading us to deviate from our original development plan.



	Year Ended December 31,
	2017			2016			2015
Proved undeveloped locations converted to proved developed wells during year	51			21			35
Proved undeveloped drilling and completion capital invested (in millions)	$	136.8		$	55.3		$	165.3
Proved undeveloped facilities capital invested (in millions)	$	11.9		$	5.3		$	5.0
Percentage of proved undeveloped reserves converted to proved developed	70		%	19		%	10		%
Prior year's proved undeveloped reserves remaining undeveloped at current year end (MMBoe)	1.6			9.6			40.8

At December 31, 2017, our proved undeveloped reserves were 44.3 MMBoe. At December 31, 2016, our proved undeveloped reserves were 18.5 MMBoe. During 2017, 13.0 MMBoe, or 70% of our December 31, 2016 proved undeveloped reserves (51 wells), were converted into proved developed reserves and required $136.8 million of drilling and completion capital and $11.9 million of facilities capital. These wells produced 2.2 MMBoe in 2017. During 2017, we added 31.7 MMBoe of proved undeveloped reserves due to drilling programs in our core development area. Positive engineering revisions increased proved undeveloped reserves by 10.8 MMBoe. During 2017, 3.9 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Positive pricing revisions increased proved undeveloped reserves by 0.2 MMBoe. The proved undeveloped reserves from December 31, 2016 that remained in the proved undeveloped reserves category at December 31, 2017 were 1.6 MMBoe.

At December 31, 2016, our proved undeveloped reserves were 18.5 MMBoe. At December 31, 2015, our proved undeveloped reserves were 43.9 MMBoe. During 2016, 8.5 MMBoe, or 19% of our December 31, 2015 proved undeveloped reserves (21 wells), were converted into proved developed reserves and required $55.3 million of drilling and completion capital and $5.3 million of facilities capital. These wells produced 1.3 MMBoe in 2016. During 2016, we added 8.4 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. Negative engineering revisions decreased proved undeveloped reserves by 0.7 MMBoe. During 2016, 24.3 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Negative pricing revisions decreased proved undeveloped reserves by 0.3 MMBoe. The proved undeveloped reserves from December 31, 2015 that remained in the proved undeveloped reserves category at December 31, 2016 were 9.6 MMBoe.

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% 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.

We use our internal reserves estimates rather than the estimates of an independent third party engineering firm because we

Table of Contents

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.


•	A comparison is made and documented of land and lease records 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 Senior Vice President of Corporate Development 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 Senior Vice President of Corporate Development 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 Senior Vice President of Corporate Development 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 40 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 in 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. Benjamin W. Johnson and Mr. John G. Hattner. Mr. Johnson, a Licensed Professional Engineer in the State of Texas (No. 124738), has has been practicing consulting petroleum engineering at NSAI since 2007 and has over two years of prior industry experience. He graduated from Texas Tech University in 2005 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

Table of Contents

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 as 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 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 public data.


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


•	The NSAI technical staff 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 shown herein of Bill Barrett's reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards." 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 2017 and 2016, we paid NSAI approximately $202,000 and $150,000, 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

Table of Contents

information for each of the periods indicated:



	Year Ended December 31,
	2017		2016		2015
Company Production Data:
Oil (MBbls)	4,203		3,885		4,401
Natural gas (MMcf)	8,952		7,170		7,764
NGLs (MBbls)	1,307		1,010		898
Combined volumes (MBoe)	7,002		6,090		6,593
Daily combined volumes (Boe/d)	19,184		16,639		18,063
DJ Basin – Production Data ⁽¹⁾:
Oil (MBbls)	3,509		3,050		2,958
Natural gas (MMcf)	8,592		6,228		6,012
NGLs (MBbls)	1,294		966		815
Combined volumes (MBoe)	6,235		5,054		4,775
Daily combined volumes (Boe/d)	17,082		13,809		13,082
Uinta Oil Program – Production Data ⁽¹⁾⁽²⁾:
Oil (MBbls)	689		830		1,420
Natural gas (MMcf)	348		900		1,728
NGLs (MBbls)	12		42		82
Combined volumes (MBoe)	759		1,022		1,790
Daily combined volumes (Boe/d)	2,079		2,792		4,904
Average Realized Prices before Hedging:
Oil (per Bbl)	$	48.37	$	38.83	$	40.06
Natural gas (per Mcf)	2.43		1.98		2.23
NGLs (per Bbl)	20.01		13.15		12.16
Combined (per Boe)	35.88		29.28		31.02
Average Realized Prices with Hedging:
Oil (per Bbl)	$	52.72	$	62.56	$	78.19
Natural gas (per Mcf)	2.52		2.46		3.75
NGLs (per Bbl)	20.01		13.15		12.16
Combined (per Boe)	38.6		44.98		58.27
Average Costs ($ per Boe):
Lease operating expense	$	3.46	$	4.58	$	6.48
Gathering, transportation and processing expense	0.37		0.39		0.53
Total production costs excluding production taxes	$	3.83	$	4.97	$	7.01
Production tax expense	2.07		1.75		1.85
Depreciation, depletion and amortization	22.85		28.18		31.14
General and administrative ⁽³⁾	6.07		6.92		8.17


(1)	The DJ Basin was the only development area that contained 15% or more of our total proved reserves as of December 31, 2017. 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, 2016 and 2015.


(2)	On December 29, 2017, we completed the sale of our remaining non-core assets in the Uinta Basin. As a result, the production and cost data related to the Uinta Basin as reported above includes values through the closing date of December 29, 2017. See Note 4 to the Consolidated Financial Statements for more information related to this divestiture.


(3)	Included in general and administrative expense is long-term cash and equity incentive compensation of $8.3 million (or $1.18 per Boe), $11.9 million (or $1.96 per Boe) and $10.8 million (or $1.64 per Boe) for the years ended December 31, 2017, 2016 and 2015, respectively.

Table of Contents

Productive Wells

The following table sets forth information at December 31, 2017 relating to the productive wells in which we owned a working interest as of that date.



	Oil		Gas
Basin/Area	Gross Wells	Net Wells	Gross Wells	Net Wells
DJ	330.0	216.9	38.0	28.3
Other	10.0	4.9	3.0	1.0
Total	340.0	221.8	41.0	29.3

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2017 relating to our leasehold acreage.



	Developed Acreage		Undeveloped Acreage
Basin/Area	Gross	Net	Gross	Net
DJ	59,761	38,702	55,364	30,858
Other	5,272	2,473	216,247	126,167	⁽¹⁾
Total	65,033	41,175	271,611	157,025


(1)	Other includes 56,344 and 63,507 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. The following table sets forth, as of December 31, 2017, the expiration periods of the net undeveloped acres by area that are subject to leases summarized in the above table of undeveloped acreage.



	Net Undeveloped Acres Expiring
Basin/Area	2018	2019	2020	2021	Thereafter	Total
DJ	5,212	3,135	5,977	4,423	12,111	30,858
Other	50,045	21,278	2,012	—	52,832	126,167
Total	55,257	24,413	7,989	4,423	64,943	157,025

Drilling Results

Table of Contents

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.



	Year Ended December 31,
	2017		2016		2015
	Gross	Net	Gross	Net	Gross	Net
Development
Productive	59.0	44.8	26.0	23.3	82.0	50.4
Dry	—	—	1.0	0.5	1.0	0.9
Exploratory
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total
Productive	59.0	44.8	26.0	23.3	82.0	50.4
Dry	—	—	1.0	0.5	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 the 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 and water 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 oil 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. Our natural gas and related NGLs are sold primarily to two gas gathering and processing companies. Based on where we operate and the availability of other purchasers and markets, we believe that our production could be sold in the market in the event that it is not sold to our existing customers. However, in some circumstances, a change in customers may entail significant transition costs. From a larger perspective, a reduction in market demand, such as a possible shift to electric vehicles, represents an additional risk factor.

During 2017, three customers individually accounted for over 10% of the Company's oil, gas and NGL production revenues. During 2016, three customers individually accounted for over 10% of the Company's oil, gas and NGL production revenues. During 2015, four customers individually accounted for over 10% of the Company's oil, gas and NGL 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 New York Mercantile Exchange ("NYMEX") with quality, location or transportation

Table of Contents

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. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. 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. Our strategic objective is to hedge 50%-70% of our anticipated production on a forward 12-month to 18-month basis. As of February 6, 2018, we have hedged 3,674,500 barrels of oil and 1,825,000 MMbtu of natural gas and 1,914,750 barrels of oil for our 2019 production at price levels that provide some economic certainty to our cash flows. Currently, seven 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. See the risk discussed below in "Item 1A. Risk Factors" under the caption "Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed".

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. 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 Amended 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;

Table of Contents


•	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 delays the 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 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, 2017, 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. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations, including organized, well-funded "keep it in the ground" efforts to turn public opinion against the use of fossil fuels.

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

National Environmental Policy Act. Oil, natural gas and NGLs exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of the Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and project alternatives. If impacts are considered significant, the agency will prepare a more detailed Environmental Impact Statement. These environmental analyses are made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that trigger the requirements of NEPA. Certain federal permits on non-federal lands may also trigger NEPA requirements. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of "hazardous wastes" and on the disposal of non-hazardous wastes. Under the oversight of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with RCRA or corresponding state programs. RCRA also imposes cleanup liability related to the mismanagement of regulated wastes. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy are currently exempt from regulation under the hazardous waste provisions of RCRA, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation, and legislation has been proposed from time to time in Congress to reverse the exemption. In addition, certain environmental groups have petitioned and sued the EPA to reverse the exemption. The EPA has entered into a consent decree with these environmental groups that commits the EPA to deciding whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector by March 2019.

Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our

Table of Contents

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. 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, storm water 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. 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. 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. In January 2018, the EPA signed a final rule delaying the applicability date of the "Waters of the United States" rule for several years while the EPA continues to conduct a substantive re-evaluation of the definition of "Waters of the United States." The final rule, if and when effective, may expand the definition of "Waters of the United States" to include wetlands, tributaries and other waters that are 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 issued several 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 finalized new regulations focused on methane emissions from the oil and gas industry in June 2016. Although the EPA has proposed a two-year stay of the effective dates of several requirements of these regulations, they are currently in effect. The Bureau of Land Management also finalized similar methane and gas-capture rules for oil and gas operations on federal and tribal leases and certain committed state or private tracts in a federally approved unit or communitized agreement. These rules are subject to ongoing litigation. In December 2017, the BLM published a rule to temporarily suspend or delay certain rule requirements until January 2019; that rule is also the subject of litigation in federal court. The EPA already requires reporting of greenhouse gases, such as CO2 and methane, from operations. In 2014 and 2017, Colorado expanded its oil and gas air regulations, including the adoption of new and additional fugitive methane emission control regulations. In addition, the EPA has lowered the national ambient air quality standard ("NAAQS") 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 triggered significant additional obligations for the State under the Clean Air Act and resulted in additional regulatory requirements for the oil and gas industry. The Denver Metro/North Front Range NAA is at risk of being reclassified again to "serious" if it does not meet the 2008 NAAQS by 2018 or obtain an extension of the deadline from the EPA. A "serious" classification would trigger significant

Table of Contents

additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements becoming applicable to our operations and significant costs and delays in obtaining necessary permits. This process could result in new or more stringent air quality control requirements applicable to our operations. 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 preliminary report in 2015, finding no systematic impact on groundwater resources. In its final report, issued in late 2016, EPA removed the conclusion of no systemic impact from the executive summary of the report, although it cited no new evidence to the contrary. 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 ("TRI"). On January 6, 2017, EPA issued a proposed rule to include natural gas processing facilities within the TRI program. 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. The BLM rescinded the rule in December 2017; however, the BLM's rescission has been challenged by several states in the United States District Court of the District of Northern California. In Colorado, certain local jurisdictions imposed moratoria or bans on hydraulic fracturing, all of which have been invalidated, including on appeal to the Colorado Supreme Court. In 2016, citizen initiatives to empower local governments to regulate or prohibit oil and gas development, and to impose a 2,500' statewide setback from occupied buildings and a variety of water ways and other natural resource areas failed to attract enough signatures to be certified for the ballot. On the other hand, another ballot initiative, supported by the industry and business community, as well as a number of elected officials made the ballot and was approved by the electorate. This "Raise the Bar" initiative was designed to make it much more difficult to qualify ballot initiatives to amend the state constitution, and raised the vote threshold to enact such measures into law. However, the more stringent ballot qualification standard has come under judicial review and may be stricken. Disputes at the local level regarding high-intensity oil and gas development in proximity to residential areas have not subsided and local ordinances or state legislation may be proposed that could result in additional restrictions on oil and gas development in some areas of Colorado. The Company participates in industry organizations mobilized to combat such measures, including by litigation where necessary.

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 March 2017, President Trump signed the Executive Order on Energy Independence which, among other things, called for a review of the Clean Power Plan. The EPA subsequently published a proposed rule to repeal the Clean Power Plan in October 2017. A final rule is expected following a comment period. 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. Recently, the University of Colorado and the University of Denver have rejected proposed divestment measures. 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. In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement. Potential future laws, regulations or even litigation 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.

Homeland Security. Legislation continues to be introduced in Congress, and development of regulations continues in the

Table of Contents

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 but cost of compliance cannot be accurately estimated at this time. Cybersecurity has been a topic of increased focus, and we have implemented several cybersecurity measures, including an emergency response plan, annual employee training, penetration tests, Supervisory Control and Data Acquisition ("SCADA") protection and firewall upgrades. We have installed a comprehensive software package to track and document our cybersecurity initiatives which are reviewed by the Executive Committee and Board on a regular basis. Our cybersecurity initiatives are an increasingly important function of our Information Technology and Legal Departments. Presently, it is not possible to accurately estimate the costs we could incur to respond to a cyber attack, 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 and local 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 and municipalities 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 archaeological 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, 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, 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 special taxing districts.

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 ("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 sales of our own production.

FERC also regulates interstate natural gas transportation rates and service conditions pursuant to the Natural Gas Act, 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. Interstate gas pipeline companies are required to provide nondiscriminatory, non-preferential transportation services to producers, marketers and other shippers regardless of whether such shippers are affiliated with an interstate pipeline company, and pursuant to such orders, regulations, and rules, interstate gas pipeline companies are required to file the tariff rates and other terms and conditions of such services with FERC.

The Energy Policy Act of 2005 (the "EPAct 2005") was signed into law in August 2005. The EPAct 2005 amends the Natural Gas Act to make it unlawful for "any entity", including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. The EPAct 2005 also gives FERC authority to impose civil penalties for violations of the Natural Gas Act or Natural Gas Policy Act up to $1 million per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the

Table of Contents

activities are conducted "in connection with" natural gas sales, purchases or transportation subject to FERC jurisdiction, thus reflecting a significant expansion of FERC's enforcement authority.

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.

Employees

As of February 6, 2018, we had 110 employees of whom 81 work in our Denver office and 29 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, 2017, 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 a field office in Greeley, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

Annual CEO Certification

As required by New York Stock Exchange rules, on June 26, 2017, 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 risks facing the Company. Additional risks not presently known to us or that we currently consider immaterial also may adversely affect our Company.

Risks Related to the Merger

The Company and Fifth Creek may fail to complete the Merger if certain required conditions, many of which are outside the companies' control, are not satisfied.

The Merger Agreement contains conditions, some of which are beyond the companies' control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Merger not occurring, even though our shareholders may have voted to approve the Merger. We cannot predict with certainty whether and when any of the conditions to the completion of the Merger will be satisfied. Any delay in completing the Merger could cause us not to realize, or delay the realization of, some or all of the benefits that we expect to achieve from the Merger. In addition, we can agree with Fifth Creek not to consummate the Merger even if our shareholders approve the Merger and the conditions to the closing of the Merger are otherwise satisfied.

Failure to complete the Merger could negatively impact the Company's stock prices and future business and

financial results.

If the Merger is not completed, we will be subject to several risks, including the following:


•	certain damages for which we may be liable to Fifth Creek under the terms and conditions of the

Merger Agreement, including a termination fee in certain circumstances;


•	payment for certain costs relating to the Merger, whether or not the Merger is completed, such as

legal, accounting, financial advisor and printing fees;


•	negative reactions from the financial markets, including declines in the price of our stock due to the

fact that current prices may reflect a market assumption that the Merger will be completed;

Table of Contents


•	diverted attention of the Company's management to the Merger rather than to our operations and pursuit

of other opportunities that could have been beneficial to it; and


•	negative impact on the Company's future growth plan, including with regard to potential acquisitions, for

which the combined company is likely to provide a stronger foundation.

The Company will be subject to various uncertainties and contractual restrictions while the Merger is pending that could adversely affect its business and operations.

Uncertainty about the effect of the Merger on customers, suppliers and vendors may have an adverse effect on the Company's business, financial condition and results of operations. It is possible that some customers, suppliers and other persons with whom the Company has business relationships may delay or defer certain business decisions, or might decide to seek to terminate, change or renegotiate their relationship with the Company as a result of the Merger, which could negatively affect the Company's financial results, as well as the market price of the Company's stock, regardless of whether the Merger is completed.

We may fail to realize the anticipated benefits of the Merger and may assume unanticipated liabilities.

The success of the Merger will depend on, among other things, our ability to combine the businesses of the Company and Fifth Creek in a manner that realizes the various benefits, growth opportunities and synergies we anticipate. Achieving the anticipated benefits of the transaction is subject to a number of risks and uncertainties. Holdco will assume all of the liabilities associated with the acquired properties and environmental, title and other problems could reduce the value of the properties to Holdco. Also, it is uncertain whether the Company's and Fifth Creek's existing operations and the acquired properties and assets can be integrated in an efficient and effective manner.

As with other acquisitions, the success of the Merger depends on, among other things, the accuracy of our assessment of the reserves and drilling locations associated with the acquired properties, future oil, NGLs and natural gas prices and operating costs and various other factors. These assessments are necessarily inexact. Although the properties to be acquired are subject to many of the risks and uncertainties to which the Company's operations are subject, risks associated with the Merger in particular include those associated with the significant size of the transaction relative to the Company's existing operations and the fact that a substantial majority of the Fifth Creek properties are undeveloped. In addition, the integration of operations following the Merger will require the attention of Holdco's management and other personnel, which may distract their attention from Holdco's day-to-day business and operations and prevent the combined company from realizing benefits from other opportunities. Completing the integration process may be more expensive than anticipated, and we cannot assure you that Holdco will be able to affect the integration of these operations smoothly or efficiently or that the anticipated benefits of the transaction will be achieved.

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

Oil and gas prices are volatile and changes in prices can significantly affect our financial results and 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 NGL 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 global demand for oil, natural gas and NGLs;


•	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 ("OPEC") 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;

Table of Contents


•	the price and availability of alternative fuels; and


•	the strength of the U.S. dollar compared to other currencies.

Lower oil, natural gas and NGL 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 therefore the quantity and the estimated present value of our 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 significantly in 2014 and 2015 and have remained low relative to prices prevailing in early 2014. Natural gas and NGL prices have also fallen significantly since mid-2014. These decreases have increased the volatility and amplitude of the other risks facing us as described in this report and have impacted our business and financial condition. If oil prices decrease from current levels, 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.

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

Drilling for oil, natural gas and NGLs may involve unprofitable efforts from wells that are productive but do not produce sufficient commercial quantities to cover 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, midstream constraints and for other reasons. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects. 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 some of our plays may be more uncertain than in other plays that are more mature and have longer established drilling and production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other formations to maximize recoveries will be ultimately successful when used in our prospects. As a result, we may incur future dry hole costs and/or impairment charges due to any of these factors.

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. 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.

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, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business and the recording of proved reserves.

Table of Contents

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. 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 NGL 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. 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:


•	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.

Table of Contents

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 cash generated by operations, sales of our equity and debt securities, proceeds from bank borrowings and sales of properties. 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 Amended 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 Amended 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 Amended Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil, natural gas and NGLs reserves as well as our revenues and results of operations.

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

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

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

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

Table of Contents

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 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 Amended Credit Facility may be limited, which would affect our ability to fund our operations.

Our Amended Credit Facility has commitments from 13 lenders. If credit markets become turbulent as a result of an economic downturn, increased regulatory oversight, 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 at times been exacerbated by increases in oil and gas supply resulting from increases in U.S. oil and gas production.

•

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


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

•

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


•	Our credit facility bears floating interest rates based on the London Interbank Offer Rate ("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.

Table of Contents


•	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 inaccurate.

Our estimates of proved reserves are based on prices and costs determined 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, 2017, 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 $429.8 million during the five years ending December 31, 2022. 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.

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:

Table of Contents


•	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 Amended Credit Facility or affiliates of such lenders. The risk that a counterparty may default on its obligations increases when overall economic conditions deteriorate. Losses resulting from adverse economic conditions or other factors may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving lower prices for our production. 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 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.

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.

Land owner demands arising as a result of a recent decision of the Wyoming Supreme Court have adverse effects on our business.

In December 2015, the Wyoming Supreme Court issued its "Pennaco" decision, the essence of which is that parties to a contract, such as a surface use agreement, remain liable for the obligations under that agreement - even when the agreement

Table of Contents

and the underlying assets have been sold and assigned to a third party - unless the agreement contains express language releasing and discharging the original party upon such subsequent assignment.

Landowners across Wyoming are making Pennaco claims against companies that sold assets to other oil and gas companies that are now in default. To date, our exposure relates to coalbed methane ("CBM") leases and wells that we sold to entities which are now essentially defunct, if not in actual bankruptcy proceedings. These operators have defaulted on several annual surface use payments, as well as leaving more than 150 CBM wells acquired from us in non-producing (shut-in) status. We have been contacted by several large ranches or their attorneys demanding payment of amounts in arrears, and that we conduct the plugging of the wells and land reclamation. Each case entails determining what contractual obligations are imposed by the applicable surface use agreement, taking into account state and federal plugging and reclamation requirements.

We obtained orders from the Wyoming Oil & Gas Conservation Commission ("WOGCC") requiring certain of the defaulting operators to "show cause" as to why the WOGCC should not authorize us to take over the wells in order to conduct plugging and reclamation operations. In response to these orders, we have reached contractual agreements that provide us with the authority to plug and abandon any or all of the wells at issue. We have explored a number of options including investigating third party interest in acquiring the wells, assumption of obligations related to the shallow CBM wells by operators holding "deep rights" under the leases, and negotiated settlement and release agreements with the ranches. It should also be noted that the WOGCC holds substantial plugging bonds posted by the defaulting operators. The Company is under no regulatory compulsion to plug these wells at this time.

At this time, transferring these wells to other companies active in Wyoming does not appear to be an available option. However, we do not believe that resolving this matter will have a material financial impact. We believe that, if necessary, the currently identified roster of shut-in wells can be plugged and reclaimed at cost of approximately $15,000 per well. There is no assurance, however, that this issue will not expand to wells sold to other purchasers of Wyoming assets previously owned by the Company.

Possible future ballot initiatives in Colorado, if approved, could have severely adverse effects on our operations, reserves and financial condition.

As previously disclosed, several statewide ballot initiatives were filed for the 2016 election cycle that sought to restrict or limit oil and natural gas development in Colorado. Proponents attempted to collect the required number of signatures to have two such proposals included on the ballot for the November 2016 election. One would have amended the Colorado constitution to impose a 2,500 foot statewide drilling setback from occupied structures and other sensitive areas. If implemented, this proposal would have had the effect of rendering the vast majority of the surface area of the state ineligible for drilling, including many of our planned future drilling locations. The second would have amended the state constitution to give local governmental authorities the ability to regulate, or to ban, oil and gas development activities within their boundaries notwithstanding state rules to the contrary. If implemented, this proposal could have caused us to be subject to onerous, and possibly inconsistent, regulations that vary from jurisdiction to jurisdiction, or to outright bans on our activities in the state. The Colorado Secretary of State determined that proponents of these proposals did not submit a sufficient number of valid signatures for the proposals to be included on the November 2016 ballot. However, similar proposals may be approved for the 2018 ballot. Because substantially all of our operations and reserves are located in Colorado, the passage and implementation of any such proposal could have a materially adverse effect on our operations, reserves, financial condition and business generally.

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.

Table of Contents

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 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 and our Amended 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 7.0% Senior Notes due 2022 ("7.0% Senior Notes"), 8.75% Senior Notes due 2025 ("8.75% Senior Notes") 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 the sustained decline in commodity prices.

As of December 31, 2017, the total outstanding principal amount of our indebtedness was approximately $627.3 million, and we had approximately $274.0 million in additional borrowing capacity under our Amended Credit Facility, which, if borrowed, would be secured debt effectively senior to the Senior 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, 2017, $300.0 million based on our June 30, 2017 proved reserves and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. As of December 31, 2017, we had no amounts outstanding under our Amended Credit Facility.

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, 2018 based on proved reserves as of December 31, 2017 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 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 senior 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 costs of doing business;


•	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.

Table of Contents

We may be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing the senior notes and our Amended Credit Facility impose on us.

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 our 2018 budget at current commodity prices. However, if commodity prices significantly decline, 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.

If we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. 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 the 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. 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.

Risks Related to Tax

We may incur more taxes as a result of new tax legislation.

The Tax Cut and Jobs Act (the "TCJA") was passed in December 2017. The TCJA includes provisions that could limit certain tax deductions:


•	interest expense is limited to 30% of our taxable income (with certain adjustments); and


•	net operating loss (NOL) related to losses incurred after 2017 are limited to 80% of taxable income but can be carried forward indefinitely.

These changes may increase our future tax liability in some circumstances. In addition, proposals are made from time to time to amend U.S. federal and state income tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling.

Our utilization of net operating loss and tax credit carryforwards may be limited based on current Internal Revenue Code restrictions and the Merger.

We have significant net operating loss ("NOL") carryforwards. Subject to certain limitations and applicable expiration dates, these tax attributes can be carried forward to reduce our federal income tax liability for future periods. Under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), our NOL carryforwards would become subject to the "section 382 limitation" if we were to experience an "ownership change." For this purpose, the term "ownership change" refers to an increase in ownership of at least 50% of our shares by certain groups of shareholders during any three-year period, as determined under certain conventions. As of December 31, 2017, we believe we have not experienced an ownership change related to Section 382.

If we were to undergo an ownership change at any time under Section 382 of the Code, our 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. Our "section 382 limitation" would generally equal the fair market value of our outstanding equity (as of the date of the ownership change) multiplied 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."

Table of Contents

We expect to incur an ownership change as a result of the Merger and therefore will likely lose a significant amount of our NOL carryforward balance. This will result in a reduction of our deferred tax asset balance related to the NOL carryforward and the valuation allowance. In addition, it will result in a charge to income tax expense as a result of the Company likely having a net deferred tax liability after the derecognition of the NOL carryforward.

With the implementation of the TCJA, we are permitted to claim a refund of our existing alternative minimum tax ("AMT") credit, 100% refundable by 2021. As of December 31, 2017, our AMT tax credit refund due was $1.4 million.

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 does not believe that the resolution of any currently pending proceeding will have a material adverse effect on our financial condition or results of operations.

Item 4. Mine Safety Disclosures.

Not applicable.

Table of Contents

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
2017
First Quarter	$	7.58	$	4.04
Second Quarter	4.69		2.75
Third Quarter	4.70		2.66
Fourth Quarter	6.93		4.05
2016
First Quarter	$	6.48	$	2.19
Second Quarter	9.38		5.26
Third Quarter	7.02		4.88
Fourth Quarter	8.24		4.61

On February 6, 2018, the closing sales price for our common stock as reported by the NYSE was $5.42 per share.

Holders. On February 6, 2018, there were 99 holders of record of our common stock.

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 2017 except pursuant to the 2017 Debt Exchange disclosed in our Current Report on Form 8-K filed with the SEC on December 15, 2017.

Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2017:



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, 2017	879	$	4.16	0	0
November 1 - 30, 2017	450	$	5.88	0	0
December 1 - 31, 2017	195	$	4.51	0	0
Total	1,524	$	4.71	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

Table of Contents

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, 2012, and $100 was invested in each of the Standard & Poors SmallCap 600 Index-Energy Sector and the Standard & Poors 500 Index at the closing price on December 31, 2012.


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



	December 31, 2012		December 31, 2013		December 31, 2014		December 31, 2015		December 31, 2016		December 31, 2017
BBG	$	100	$	151	$	64	$	22	$	39	$	29
S&P SmallCap 600- Energy	100		138		88		46		63		46
S&P 500	100		130		144		143		157		191

Item 6. Selected Financial Data.

The following table presents our selected historical financial data for the years ended December 31, 2017, 2016, 2015, 2014 and 2013. 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, 2017, 2016 and 2015 and the balance sheet information as of December 31, 2017 and 2016 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, 2014 and 2013 and the balance sheet information at December 31, 2015, 2014 and 2013 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.

Table of Contents



	Year Ended December 31,
	2017			2016			2015			2014			2013
	(in thousands, except per share data)
Statement of Operations Data:
Operating Revenues:
Oil, gas and NGL production ⁽¹⁾	$	251,215		$	178,328		$	204,537		$	464,137		$	565,555
Other operating revenues	1,624			491			3,355			8,154			2,538
Total operating revenues	252,839			178,819			207,892			472,291			568,093
Operating Expenses:
Lease operating expense	24,223			27,886			42,753			60,308			70,217
Gathering, transportation and processing expense	2,615			2,365			3,482			35,437			67,269
Production tax expense	14,476			10,638			12,197			31,333			27,172
Exploration expense	83			83			153			453			337
Impairment, dry hole costs and abandonment expense	49,553			4,249			575,310			46,881			238,398
(Gain) loss on sale of properties	(92		)	1,078			1,745			100,407			—
Depreciation, depletion and amortization	159,964			171,641			205,275			235,805			279,775
Unused commitments	18,231			18,272			19,099			4,434			—
General and administrative expense ⁽²⁾	42,476			42,169			53,890			53,361			64,902
Merger transaction expense	8,749			—			—			—			—
Other operating expenses, net	(1,514		)	(316		)	—			—			—
Total operating expenses	318,764			278,065			913,904			568,419			748,070
Operating Income (Loss)	(65,925		)	(99,246		)	(706,012		)	(96,128		)	(179,977		)
Other Income and Expense:
Interest and other income	1,359			235			565			1,294			1,646
Interest expense	(57,710		)	(59,373		)	(65,305		)	(69,623		)	(88,507		)
Commodity derivative gain (loss)	(9,112		)	(20,720		)	104,147			197,447			(23,068		)
Gain (loss) on extinguishment of debt	(8,239		)	8,726			1,749			—			(21,460		)
Total other income (expense)	(73,702		)	(71,132		)	41,156			129,118			(131,389		)
Income (Loss) before Income Taxes	(139,627		)	(170,378		)	(664,856		)	32,990			(311,366		)
(Provision for) Benefit from Income Taxes	1,402			—			177,085			(17,909		)	118,633
Net Income (Loss)	$	(138,225	)	$	(170,378	)	$	(487,771	)	$	15,081		$	(192,733	)
Net Income (Loss) per Common Share:
Basic	$	(1.80	)	$	(3.08	)	$	(10.10	)	$	0.31		$	(4.06	)
Diluted	$	(1.80	)	$	(3.08	)	$	(10.10	)	$	0.31		$	(4.06	)
Weighted average common shares outstanding, basic	76,859			55,384			48,303			48,011			47,497
Weighted average common shares outstanding, diluted	76,859			55,384			48,303			48,436			47,497

(1)

The oil, gas and NGL production revenue decrease from 2013 to 2016 reflects the decrease in revenues due to divestitures and a decrease in commodity prices. In addition, oil, gas and NGL production revenues include the effects of cash flow hedging transactions for the years ended December 31, 2014 and 2013. 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)	Included in general and administrative expense is long-term cash and equity incentive compensation of $8.3 million, $11.9 million, $10.8 million, $11.4 million and $15.8 million for the years ended December 31, 2017, 2016, 2015, 2014 and 2013, respectively.

Table of Contents



	Year Ended December 31,
	2017			2016			2015			2014			2013
	(in thousands)
Selected Cash Flow and Other Financial Data:
Net income (loss)	$	(138,225	)	$	(170,378	)	$	(487,771	)	$	15,081		$	(192,733	)
Depreciation, depletion, impairment and amortization	209,062			171,824			777,713			275,988			506,326
Other non-cash items	45,603			124,552			(83,760		)	(59,970		)	(32,600		)
Change in assets and liabilities	5,550			(4,262		)	(12,504		)	30,618			(15,728		)
Net cash provided by operating activities	$	121,990		$	121,736		$	193,678		$	261,717		$	265,265
Capital expenditures ⁽¹⁾	$	260,659		$	98,292		$	287,411		$	569,312		$	474,031

(1)

Includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $0.5 million, $4.1 million, $3.0 million, $7.2 million and $12.2 million for the years ended December 31, 2017, 2016, 2015, 2014 and 2013, respectively. Also includes furniture, fixtures and equipment costs of $1.0 million, $1.1 million, $1.3 million, $3.7 million and $1.3 million for the years ended December 31, 2017, 2016, 2015, 2014 and 2013, respectively.



	As of December 31,
	2017		2016		2015		2014		2013
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	314,466	$	275,841	$	128,836	$	165,904	$	54,595
Other current assets	53,197		42,611		145,481		260,201		102,652
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment	1,012,610		1,055,049		1,160,898		1,730,172		2,184,183
Other property and equipment, net of depreciation	6,270		7,100		9,786		13,715		18,313
Oil and natural gas properties held for sale, net of accumulated depreciation, depletion, amortization and impairment	—		—		—		9,234		—
Other assets ⁽¹⁾	4,163		4,740		61,519		54,822		9,537
Total assets	$	1,390,706	$	1,385,341	$	1,506,520	$	2,234,048	$	2,369,280
Current liabilities	$	148,934	$	85,018	$	145,231	$	264,687	$	192,719
Long-term debt, net of debt issuance costs ⁽¹⁾	617,744		711,808		794,652		792,786		966,849
Other long-term liabilities	25,474		16,972		17,221		147,087		203,994
Stockholders' equity	598,554		571,543		549,416		1,029,488		1,005,718
Total liabilities and stockholders' equity	$	1,390,706	$	1,385,341	$	1,506,520	$	2,234,048	$	2,369,280

(1)

We adopted ASU 2015-03 and ASU 2015-15 effective January 1, 2016, which required that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability and as a result, $8.7 million, $10.4 million and $12.2 million of debt issuance costs related to our long-term debt were reclassified from deferred financing costs and other noncurrent assets to long-term debt in our consolidated balance sheet as of December 31, 2015, 2014 and 2013, respectively.

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

Table of Contents

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.

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, 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, 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,
	2017		2016		2015
Estimated net proved reserves (MMBoe)	85.8		54.9		83.7
Standardized measure ⁽¹⁾ (in millions)	$	829.3	$	329.3	$	327.6

(1)

December 31, 2017 reserves were based on average prices of $51.34 WTI per Bbl of oil, $2.98 Henry Hub per Mcf of natural gas and $27.40 per Bbl of NGLs. December 31, 2016 reserves were based on average prices of $42.75 WTI for oil, $2.48 Henry Hub for natural gas and $19.70 for NGLs. December 31, 2015 reserves were based on average prices of $50.28 WTI for oil, $2.59 Henry Hub for natural gas and $20.37 for NGLs.

Commodity prices are inherently volatile and are influenced by many factors outside of our control. Our strategic objective is to hedge 50%-70% of our anticipated production on a forward 12-month to 18-month basis. As of February 6, 2018, we have hedged 3,674,500 barrels of oil and 1,825,000 MMbtu of natural gas and 1,914,750 barrels of oil for our 2019 production at price levels that provide some economic certainty to our cash flows. We focus our efforts on increasing oil, natural gas and NGL 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.

Significant Business Developments

Table of Contents

In December 2017, we entered into the Merger Agreement with Fifth Creek. Fifth Creek is an exploration and production company focusing on the development of oil and gas reserves from the DJ Basin. Fifth Creek's properties include approximately 81,000 net acres in Weld County in the DJ Basin, substantially all of which are operated. The assets we will acquire also include 62 producing standard-length lateral wells and 7 producing extended-reach lateral wells. We expect to close the Merger on or about March 19, 2018. See "Items 1. and 2. Business and Properties - Business - Significant Business Developments - Pending Merger with Fifth Creek Operating Company, LLC" for additional information.

On December 15, 2017, we completed the 2017 Debt Exchange, pursuant to which we issued 10,863,000 shares of our common stock in exchange for $50.0 million principal amount of 7.0% Senior Notes. Immediately after consummation of the 2017 Debt Exchange, $350.0 million aggregate principal amount of the 7.0% Senior Notes remained outstanding.

Results of Operations

Year Ended December 31, 2017 Compared with Year Ended December 31, 2016

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

Table of Contents



	Year Ended December 31,						Increase (Decrease)
	2017			2016			Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	251,215		$	178,328		$	72,887		41	%
Other operating revenues	1,624			491			1,133			231	%
Total operating revenues	$	252,839		$	178,819		$	74,020		41	%
Operating Expenses
Lease operating expense	$	24,223		$	27,886		$	(3,663	)	(13	)%
Gathering, transportation and processing expense	2,615			2,365			250			11	%
Production tax expense	14,476			10,638			3,838			36	%
Exploration expense	83			83			—			—	%
Impairment, dry hole costs and abandonment expense	49,553			4,249			45,304			*nm
(Gain) loss on sale of properties	(92		)	1,078			(1,170		)	*nm
Depreciation, depletion and amortization	159,964			171,641			(11,677		)	(7	)%
Unused commitments	18,231			18,272			(41		)	—	%
General and administrative expense ⁽¹⁾	42,476			42,169			307			1	%
Merger transaction expense	8,749			—			8,749			*nm
Other operating expenses, net	(1,514		)	(316		)	(1,198		)	*nm
Total operating expenses	$	318,764		$	278,065		$	40,699		15	%
Production Data:
Oil (MBbls)	4,203			3,885			318			8	%
Natural gas (MMcf)	8,952			7,170			1,782			25	%
NGLs (MBbls)	1,307			1,010			297			29	%
Combined volumes (MBoe)	7,002			6,090			912			15	%
Daily combined volumes (Boe/d)	19,184			16,639			2,545			15	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	48.37		$	38.83		$	9.54		25	%
Natural gas (per Mcf)	2.43			1.98			0.45			23	%
NGLs (per Bbl)	20.01			13.15			6.86			52	%
Combined (per Boe)	35.88			29.28			6.60			23	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	52.72		$	62.56		$	(9.84	)	(16	)%
Natural gas (per Mcf)	2.52			2.46			0.06			2	%
NGLs (per Bbl)	20.01			13.15			6.86			52	%
Combined (per Boe)	38.60			44.98			(6.38		)	(14	)%
Average Costs (per Boe):
Lease operating expense	$	3.46		$	4.58		$	(1.12	)	(24	)%
Gathering, transportation and processing expense	0.37			0.39			(0.02		)	(5	)%
Production tax expense	2.07			1.75			0.32			18	%
Depreciation, depletion and amortization	22.85			28.18			(5.33		)	(19	)%
General and administrative expense ⁽¹⁾	6.07			6.92			(0.85		)	(12	)%


*	Not meaningful.


(1)	Included in general and administrative expense is long-term cash and equity incentive compensation of $8.3 million (or $1.18 per Boe) and $11.9 million (or $1.96 per Boe) for the years ended December 31, 2017 and 2016, respectively.

Production Revenues and Volumes. Production revenues increased to $251.2 million for the year ended December 31, 2017 from $178.3 million for the year ended December 31, 2016. The increase in production revenues was due to a 23%

Table of Contents

increase in the average realized prices per Boe before hedging and a 15% increase in production volumes. The increase in average prices increased production revenues by approximately $40.2 million, while the increase in production volumes increased production revenues by approximately $32.7 million.

Total production volumes of 7.0 MMBoe for the year ended December 31, 2017 increased from 6.1 MMBoe for the year ended December 31, 2016 primarily due to a 23% increase in the DJ Basin as a result of new wells placed into production, offset by a 26% decrease in production from the Uinta Oil Program primarily due to the sale of certain non-core Uinta Oil Program assets during July 2016. Additional information concerning production is in the following table:



	Year Ended December 31, 2017				Year Ended December 31, 2016				% Increase (Decrease)
	Oil	NGL	Natural Gas	Total	Oil	NGL	Natural Gas	Total	Oil		NGL		Natural Gas		Total
	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)		(MBbls)		(MMcf)		(MBoe)
DJ Basin	3,509	1,294	8,592	6,235	3,050	966	6,228	5,054	15	%	34	%	38	%	23	%
Uinta Oil Program	689	12	348	759	830	42	900	1,022	(17	)%	(71	)%	(61	)%	(26	)%
Other	5	1	12	8	5	2	42	14	*nm		*nm		*nm		*nm
Total	4,203	1,307	8,952	7,002	3,885	1,010	7,170	6,090	8	%	29	%	25	%	15	%


*	Not meaningful.

Lease Operating Expense ("LOE"). LOE decreased to $3.46 per Boe for the year ended December 31, 2017 from $4.58 per Boe for the year ended December 31, 2016. The decrease per Boe for the year ended December 31, 2017 compared with the year ended December 31, 2016 is primarily related to operational efficiencies and sales of certain non-core assets in the Uinta Oil Program during July 2016, which had relatively high LOE costs on a per Boe basis.

Production Tax Expense. Total production taxes increased to $14.5 million for the year ended December 31, 2017 from $10.6 million for the year ended December 31, 2016. The increase is attributable to the 23% increase in average realized prices before hedging and the 15% increase in production. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. We expect production taxes as a percentage of oil, natural gas and NGL sales to be approximately 7.5% in 2018.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the years ended December 31, 2017 and 2016 is summarized below:



	Year Ended December 31,
	2017			2016
	(in thousands)
Impairment of proved oil and gas properties	$	37,945	⁽¹⁾	$	—
Impairment of unproved oil and gas properties	11,153		⁽²⁾	183
Dry hole costs	—			97
Abandonment expense	455			3,969
Total impairment, dry hole costs and abandonment expense	$	49,553		$	4,249


(1)	The Company recognized a non-cash impairment charge associated with the Company's Uinta Oil Program proved properties during the year ended December 31, 2017. The properties were sold on December 29, 2017.


(2)	As a result of no future plans to develop certain acreage and/or estimated market values below carrying value, the Company recognized non-cash impairment charges of $9.1 million associated with certain unproved properties in the Cottonwood Gulch area of the Piceance Basin and $2.1 million associated with certain non-core unproved properties in the DJ Basin.

We review our oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever we conclude the carrying value may not be recoverable, we estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production,

Table of Contents

commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. We do not believe that the undiscounted future net cash flows of our oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, we utilize the income valuation technique, which involves calculating the present value of future net cash flows, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell. The estimated fair value of assets held for sale may be materially different from sales proceeds that we eventually realize due to a number of factors including but not limited to the differences in expected future commodity pricing, location and quality differentials, our relative desire to dispose of such properties based on facts and circumstances impacting our business at the time we agree to sell, such as our position in the field subsequent to the sale and plans for future acquisitions or development in core areas.

Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities.

Given current and projected future commodity prices, we will continue to review our acreage position and future drilling plans. In addition, we will assess the carrying value of our properties relative to their estimated future net cash flows. Estimated future net cash flows from our properties are based on our aggregate best estimates of future production, commodity pricing, gathering and transportation deducts, production tax rates, lease operating expenses and future development costs as of the balance sheet date.

Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $160.0 million for the year ended December 31, 2017 compared with $171.6 million for the year ended December 31, 2016. The decrease of $11.7 million was the result of a 19% decrease in the DD&A rate, offset by a 15% increase in production for the year ended December 31, 2017 compared with the year ended December 31, 2016. The decrease in the DD&A rate accounted for a decrease of $36.9 million in DD&A expense, while the increase in production accounted for a $25.3 million increase in DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis with a common geological structure using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the year ended December 31, 2017, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $22.85 per Boe compared with $28.18 per Boe for the year ended December 31, 2016.

Unused Commitments. Unused commitments were $18.2 million for the year ended December 31, 2017 compared to $18.3 million for the year ended December 31, 2016. 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 monthly transportation charges regardless of the amount of pipeline capacity utilized. These transportation contracts expire July 31, 2021.

General and Administrative Expense. General and administrative expense increased to $42.5 million for the year ended December 31, 2017 from $42.2 million for the year ended December 31, 2016 primarily due to an increase in variable employee compensation related to performance, legal and professional services fees, offset by a decrease in long-term cash and equity compensation discussed below.

Table of Contents

Included in general and administrative expense is long-term cash and equity incentive compensation of $8.3 million and $11.9 million for the years ended December 31, 2017 and 2016, respectively. The components of long-term cash and equity incentive compensation for each of the years ended December 31, 2017 and 2016 are shown in the following table:



	Year Ended December 31,
	2017		2016
	(in thousands)
Nonvested common stock and stock options	$	6,410	$	8,573
Nonvested common stock units	690		883
Nonvested performance-based cash units ⁽¹⁾⁽²⁾	1,189		2,485
Total	$	8,289	$	11,941


(1)	The performance-based cash units will be settled in cash for the performance metrics that are met.


(2)	The performance cash units are accounted for as liability awards and fair valued at each reporting date. The weighted average fair value share price decreased from $8.89 as of December 31, 2016 to $5.10 as of December 31, 2017.

Merger Transaction Expense. Merger transaction expense was $8.7 million for the year ended December 31, 2017. We entered into the Merger Agreement on December 4, 2017 and expect to close on or about March 19, 2018. Transaction expenses included advisory, banking, legal, and accounting fees that had been incurred as of December 31, 2017 and will not be capitalized as part of the Merger. We expect to incur an estimated $3.1 million of additional expenses through the closing of the Merger in 2018.

Interest Expense. Interest expense decreased to $57.7 million for the year ended December 31, 2017 from $59.4 million for the year ended December 31, 2016. The decrease for the year ended December 31, 2017 was primarily due to a decrease in the outstanding debt balance due to debt exchanged for common stock in June 2016 and the redemption of our remaining 7.625% Senior Notes and Convertible Notes in May 2017, offset by the issuance of our 8.75% Senior Notes in April 2017. See Note 5 for additional information. Our weighted average interest rate for the year ended December 31, 2017 was 8.1% compared with 7.9% for the year ended December 31, 2016.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a loss of $9.1 million for the year ended December 31, 2017 compared to a loss of $20.7 million for the year ended December 31, 2016. The decreased loss for the year ended December 31, 2017 from the year ended December 31, 2016 is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of December 31, 2017 and December 31, 2016.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:



	Year Ended December 31,
	2017			2016
	(in thousands)
Realized gain (loss) on derivatives	$	19,099		$	95,598
Prior year unrealized (gain) loss transferred to realized (gain) loss	(4,053		)	(99,809		)
Unrealized gain (loss) on derivatives	(24,158		)	(16,509		)
Total commodity derivative gain (loss)	$	(9,112	)	$	(20,720	)

In 2017, approximately 62% of our oil volumes and 39% of our natural gas volumes were covered by financial hedges, which resulted in increases in oil revenues of $18.3 million and natural gas revenues of $0.8 million after settlements for all commodity derivatives. In 2016, approximately 71% of our oil volumes and 24% of our natural gas volumes were covered by financial hedges, which resulted in increases in oil revenues of $92.2 million and natural gas revenues of $3.4 million after settlements for all commodity derivatives.

Income Tax (Expense) Benefit. For the year ended December 31, 2017, we continue to record a valuation allowance against our deferred tax assets, which would ordinarily reduce the effective tax to zero. However, the TCJA has allowed us to eliminate the valuation allowance related to the alternative minimum tax credits, resulting in an income tax benefit of $1.4 million. For the year ended December 31, 2016, we recorded a full valuation allowance against our deferred tax assets, reducing our effective tax rate to zero. In regard to the valuation allowance recorded against our deferred tax asset balance, we

Table of Contents

considered all available evidence in assessing the need for a valuation allowance. Such evidence included the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. Additionally, for both the 2017 and 2016 periods, our effective tax rate differs from the federal statutory rate as a result of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as the effect of state income taxes.

Table of Contents

Results of Operations

Year Ended December 31, 2016 Compared with Year Ended December 31, 2015

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



	Year Ended December 31,					Increase (Decrease)
	2016			2015		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	178,328		$	204,537	$	(26,209	)	(13	)%
Other operating revenues	491			3,355		(2,864		)	(85	)%
Total operating revenues	$	178,819		$	207,892	$	(29,073	)	(14	)%
Operating Expenses
Lease operating expense	$	27,886		$	42,753	$	(14,867	)	(35	)%
Gathering, transportation and processing expense	2,365			3,482		(1,117		)	(32	)%
Production tax expense	10,638			12,197		(1,559		)	(13	)%
Exploration expense	83			153		(70		)	(46	)%
Impairment, dry hole costs and abandonment expense	4,249			575,310		(571,061		)	(99	)%
(Gain) loss on sale of properties	1,078			1,745		(667		)	(38	)%
Depreciation, depletion and amortization	171,641			205,275		(33,634		)	(16	)%
Unused commitments	18,272			19,099		(827		)	(4	)%
General and administrative expense ⁽¹⁾	42,169			53,890		(11,721		)	(22	)%
Other operating expenses, net	(316		)	—		(316		)	*nm
Total operating expenses	$	278,065		$	913,904	$	(635,839	)	(70	)%
Production Data:
Oil (MBbls)	3,885			4,401		(516		)	(12	)%
Natural gas (MMcf)	7,170			7,764		(594		)	(8	)%
NGLs (MBbls)	1,010			898		112			12	%
Combined volumes (MBoe)	6,090			6,593		(503		)	(8	)%
Daily combined volumes (Boe/d)	16,639			18,063		(1,424		)	(8	)%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	38.83		$	40.06	$	(1.23	)	(3	)%
Natural gas (per Mcf)	1.98			2.23		(0.25		)	(11	)%
NGLs (per Bbl)	13.15			12.16		0.99			8	%
Combined (per Boe)	29.28			31.02		(1.74		)	(6	)%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	62.56		$	78.19	$	(15.63	)	(20	)%
Natural gas (per Mcf)	2.46			3.75		(1.29		)	(34	)%
NGLs (per Bbl)	13.15			12.16		0.99			8	%
Combined (per Boe)	44.98			58.27		(13.29		)	(23	)%
Average Costs (per Boe):
Lease operating expense	$	4.58		$	6.48	$	(1.90	)	(29	)%
Gathering, transportation and processing expense	0.39			0.53		(0.14		)	(26	)%
Production tax expense	1.75			1.85		(0.10		)	(5	)%
Depreciation, depletion and amortization	28.18			31.14		(2.96		)	(10	)%
General and administrative expense ⁽¹⁾	6.92			8.17		(1.25		)	(15	)%


*	Not meaningful.


(1)	Included in general and administrative expense is long-term cash and equity incentive compensation of $11.9 million (or $1.96 per Boe) and $10.8 million (or $1.64 per Boe) for the years ended December 31, 2016 and 2015, respectively.

Table of Contents

Production Revenues and Volumes. Production revenues decreased to $178.3 million for the year ended December 31, 2016 from $204.5 million for the year ended December 31, 2015. The decrease in production revenues was due to an 8% decrease in production volumes and a 6% decrease in the average realized prices per Boe before hedging. The decrease in production volumes reduced production revenues by approximately $14.7 million, while the decrease in average prices decreased production revenues by approximately $11.5 million.

Total production volumes of 6.1 MMBoe for the year ended December 31, 2016 decreased from 6.6 MMBoe for the year ended December 31, 2015. The decrease is primarily related to a 43% decrease in production from the Uinta Oil Program due to natural production declines with no significant drilling or recompletion activities to offset these declines as well as the sale of certain non-core Uinta Oil Program assets during the year ended December 31, 2016. The overall production volume decrease was offset by an increase in the DJ Basin production volumes, which were partially offset by non-core asset sales completed during the year ended December 31, 2015. Additional information concerning production is in the following table:



	Year Ended December 31, 2016				Year Ended December 31, 2015				% Increase (Decrease)
	Oil	NGL	Natural Gas	Total	Oil	NGL	Natural Gas	Total	Oil		NGL		Natural Gas		Total
	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)		(MBbls)		(MMcf)		(MBoe)
DJ Basin	3,050	966	6,228	5,054	2,958	815	6,012	4,775	3	%	19	%	4	%	6	%
Uinta Oil Program	830	42	900	1,022	1,420	82	1,728	1,790	(42	)%	(49	)%	(48	)%	(43	)%
Other	5	2	42	14	23	1	24	28	(78	)%	100	%	75	%	(50	)%
Total	3,885	1,010	7,170	6,090	4,401	898	7,764	6,593	(12	)%	12	%	(8	)%	(8	)%

Other Operating Revenues. Other operating revenues decreased to $0.5 million for the year ended December 31, 2016 from $3.4 million for the year ended December 31, 2015. Other operating revenues for 2016 consisted of $1.2 million related to gathering and compression fees received from third parties, offset by revised third party gas processing statements, which reduced production revenues associated with sold properties in the Piceance Basin by $0.7 million. The Piceance Basin properties were sold in September 2014.

Other operating revenues for 2015 consisted of a $1.3 million true up related to the sold properties in the West Tavaputs area of the Uinta Basin. The West Tavaputs properties were sold in December 2013. In addition, other operating revenues for 2015 included income of $1.6 million related to gathering and compression fees received from third parties and $0.5 million related to the sale of seismic data.

Lease Operating Expense. LOE decreased to $4.58 per Boe for the year ended December 31, 2016 from $6.48 per Boe for the year ended December 31, 2015. The decrease per Boe for the year ended December 31, 2016 compared with the year ended December 31, 2015 is primarily related to operational efficiencies, a decrease in service industry costs, reduced workover activity in the Uinta Basin and sales of certain non-core assets in the DJ and Uinta Basins, which had higher LOE costs on a per Boe basis.

Production Tax Expense. Total production taxes decreased to $10.6 million for the year ended December 31, 2016 from $12.2 million for the year ended December 31, 2015. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 6.0% for the years ended December 31, 2016 and 2015.

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

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the years ended December 31, 2016 and 2015 is summarized below:

Table of Contents



	Year Ended December 31,
	2016		2015
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	—	$	559,282	⁽¹⁾
Non-cash impairment of unproved oil and gas properties	183		13,156		⁽¹⁾
Dry hole costs	97		123
Abandonment expense	3,969		2,749
Total non-cash impairment, dry hole costs and abandonment expense	$	4,249	$	575,310


(1)	Due to the decline in oil prices, we recognized a non-cash impairment charge associated with the proved and unproved oil and gas properties in the Uinta Oil Program for the year ended December 31, 2015.

(Gain) Loss on Sale of Properties. (Gain) loss on sale of properties decreased to a loss of $1.1 million for the year ended December 31, 2016 from a loss of $1.7 million for the year ended December 31, 2015. The loss on sale of properties for the year ended December 31, 2016 consisted of a $1.9 million loss related to a contingent contractual obligation associated with previously sold properties, offset by post-closing adjustments on previously sold properties. The loss on sale of properties for the year ended December 31, 2015 is primarily related to the loss on the sale of frac tank trailers previously used in completion operations in the amount of $2.4 million, offset by post-closing adjustments associated with previously sold properties.

Depreciation, Depletion and Amortization. DD&A decreased to $171.6 million for the year ended December 31, 2016 compared with $205.3 million for the year ended December 31, 2015. The decrease of $33.6 million was the result of an 8% decrease in production for the year ended December 31, 2016 compared with the year ended December 31, 2015, as well as a 10% decrease in the DD&A rate. The decrease in production accounted for a $15.6 million decrease in DD&A expense, while the decrease in the DD&A rate accounted for a decrease of $18.0 million in DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis with a common geological structure using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the year ended December 31, 2016, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $28.18 per Boe compared with $31.14 per Boe for the year ended December 31, 2015.

Unused Commitments. Unused commitments were $18.3 million for the year ended December 31, 2016 compared to $19.1 million for the year ended December 31, 2015. 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 September 2014 (see Note 4 of the Notes to Consolidated Financial Statements for more information related to these divestitures). 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. These transportation contracts expire July 31, 2021 and have a remaining obligation of $85.6 million. 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.

In addition, unused commitment expense for the year ended December 31, 2015 included $1.4 million associated with a

take-or-pay purchase agreement for the supply of carbon dioxide ("CO2"). The agreement imposes a minimum volume

commitment to purchase CO2 to be used in fracture stimulation operations at a contracted price. Since we did not take delivery of the minimum volume required, we were obligated to pay the total deficiency of $1.4 million at the end of the contract term, November 30, 2015.

General and Administrative Expense. General and administrative expense decreased to $42.2 million for the year ended December 31, 2016 from $53.9 million for the year ended December 31, 2015 primarily due to a decrease in employee compensation and benefits.

Included in general and administrative expense is long-term cash and equity incentive compensation of $11.9 million and $10.8 million for the years ended December 31, 2016 and 2015, respectively. The components of long-term cash and equity incentive compensation for each of the years ended December 31, 2016 and 2015 are shown in the following table:

Table of Contents



	Year Ended December 31,
	2016		2015
	(in thousands)
Nonvested common stock and stock options	$	8,573	$	9,025
Shares issued for 401(k) plan ⁽¹⁾	—		273
Nonvested common stock units	883		1,115
Nonvested performance-based cash units ⁽²⁾	2,485		427
Total	$	11,941	$	10,840


(1)	Beginning in the second quarter of 2015, the employer matching contribution to the employees 401(k) account was paid entirely in cash.


(2)	The performance-based cash units will be settled in cash for the performance metrics that are met.

Interest Expense. Interest expense decreased to $59.4 million for the year ended December 31, 2016 from $65.3 million for the year ended December 31, 2015. The decrease for the year ended December 31, 2016 was primarily due to the debt exchange for common stock to reduce our average debt balance. See Note 10 for additional information. Our weighted average interest rate for the year ended December 31, 2016 was 7.9% compared with 8.1% for the year ended December 31, 2015.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a loss of $20.7 million for the year ended December 31, 2016 compared to a gain of $104.1 million for the year ended December 31, 2015. The change to a loss for the year ended December 31, 2016 from a gain for the year ended December 31, 2015 is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of December 31, 2016 and December 31, 2015.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:



	Year Ended December 31,
	2016			2015
	(in thousands)
Realized gain (loss) on derivatives	$	95,598		$	179,652
Prior year unrealized (gain) loss transferred to realized (gain) loss	(99,809		)	(145,226		)
Unrealized gain (loss) on derivatives	(16,509		)	69,721
Total commodity derivative gain (loss)	$	(20,720	)	$	104,147

In 2016, approximately 71% of our oil volumes and 24% of our natural gas volumes were covered by financial hedges, which resulted in increases in oil revenues of $92.2 million and natural gas revenues of $3.4 million after settlements for all commodity derivatives. In 2015, approximately 91% of our oil volumes and 88% of our natural gas volumes were covered by financial hedges, which resulted in increases in oil revenues of $167.8 million and natural gas revenues of $11.8 million after settlements for all commodity derivatives.

Income Tax (Expense) Benefit. For the year ended December 31, 2016, we continue to record a full valuation allowance against our deferred tax assets, reducing our effective tax rate to zero. For the year ended December 31, 2015, the income tax benefit was $177.1 million and we had a valuation allowance of $75.0 million, resulting in an effective tax rate of 26.6%. In regard to the valuation allowance recorded against our deferred tax asset balance, we considered all available evidence in assessing the need for a valuation allowance. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. Additionally, for both the 2016 and 2015 periods, our effective tax rate differs from the federal statutory rate as a result of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as the effect of state income taxes.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, bank credit facilities, proceeds from sale-leasebacks, joint exploration

Table of Contents

agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources available to us to meet our future financial obligations, fund planned capital expenditure activities and ensure adequate liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources being available to us. We believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations and under our Amended Credit Facility for our planned uses of capital over the next twelve months.

At December 31, 2017, we had cash and cash equivalents of $314.5 million and no amounts outstanding under our Amended Credit Facility. At December 31, 2016, we had cash and cash equivalents of $275.8 million and no amounts outstanding under our Amended Credit Facility. Our borrowing base was $300.0 million as of December 31, 2017. Our effective borrowing capacity was reduced by $26.0 million to $274.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement. The borrowing base is dependent on our proved reserves and hedge position and is calculated using future commodity pricing provided by our lenders, and may be adjusted in the future at the sole discretion of the lenders.

On December 4, 2017, we entered into the Merger Agreement with Fifth Creek. Upon consummation of the Merger, each share of our common stock will be converted into the right to receive one share of New Parent common stock and Holdings will receive 100 million shares of New Parent common stock. Under the Merger Agreement, Fifth Creek may incur up to a total of $54 million in indebtedness prior to the closing of the Merger. We expect to close the Merger on or about March 19, 2018. See "Items 1. and 2. Business and Properties - Business - Significant Business Developments - Pending Merger with Fifth Creek Operating Company, LLC" for additional information. We believe that our capital resources are sufficient to fund the expected capital programs of the combined companies for the next two years.

Cash Flow from Operating Activities

Net cash provided by operating activities was $122.0 million, $121.7 million and $193.7 million in 2017, 2016 and 2015, respectively. The changes in net cash provided by operating activities are discussed above in "Results of Operations". The increase in cash provided by operating activities from 2016 to 2017 was primarily due to an increase in production revenues, offset by a decrease in cash from derivative settlements. The decrease in net cash provided by operating activities from 2015 to 2016 was primarily due to a decrease in production revenues related to asset sales in 2015, offset by lower lease operating and production tax expenses in 2016.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our production revenue. At December 31, 2017, we had in place crude oil swaps covering portions of our 2018 and 2019 production and natural gas swaps covering portions of our 2018 production.

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

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. All changes in the derivative's fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.

At December 31, 2017, the estimated fair value of all of our commodity derivative instruments was a net liability of $25.1 million summarized in the following table, comprised of current and long-term liabilities.

Table of Contents



Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price	Fair Market Value (in thousands)
Swap Contracts:
2018
Oil	3,444,500	Bbls	$	53.01	WTI	$	(21,509	)
Natural gas	1,825,000	MMbtu	$	2.68	NWPL	570
2019
Oil	1,367,250	Bbls	$	52.85	WTI	(4,119		)
Total						$	(25,058	)

The following table includes all hedges entered into subsequent to December 31, 2017 through February 6, 2018:



Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price
Swap Contracts:
2018
Oil	230,000	Bbls	$	61.62	WTI
2019
Oil	547,500	Bbls	$	57.47	WTI

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

It is our policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. Our derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. ("ISDA") Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Amended Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Amended Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed to us under the derivative contracts. Where the counterparty is not a lender under the Amended Credit Facility, we may not be able to set-off amounts owed by us under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility.

Capital Expenditures

Our capital expenditures are summarized in the following tables for the periods indicated:



	Year Ended December 31,
Basin/Area	2017		2016		2015
	(in millions)
DJ	$	251.5	$	95.5	$	250.3
Uinta Oil Program	8.2		1.4		34.6
Powder River Oil	—		—		1.1
Other	1.0		1.4		1.4
Total ⁽¹⁾	$	260.7	$	98.3	$	287.4

Large accelerated filer

Accelerated filer

Non-accelerated filer

o (Do not check if a smaller reporting company)

Smaller reporting company

Emerging growth company

BILL BARRETT CORP 10-K