Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34 Filing Table of Contents
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2: EX-2.1 Plan of Acquisition, Reorganization, Arrangement, HTML 428K
Liquidation or Succession
3: EX-10.12 Material Contract HTML 72K
5: EX-21.1 Subsidiaries List HTML 28K
6: EX-23.1 Consent of Experts or Counsel HTML 29K
7: EX-23.2 Consent of Experts or Counsel HTML 33K
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12: EX-99.2 Miscellaneous Exhibit HTML 43K
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29: R11 Divestitures HTML 58K
30: R12 Long-Term Debt HTML 121K
31: R13 Asset Retirement Obligations HTML 56K
32: R14 Fair Value Measurements HTML 114K
33: R15 Derivative Instruments HTML 110K
34: R16 Income Taxes HTML 129K
35: R17 Stockholders' Equity HTML 75K
36: R18 Equity Incentive Compensation Plans and Other HTML 253K
Employee Benefits
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38: R20 Commitments and Contingencies HTML 55K
39: R21 Guarantor Subsidiaries HTML 393K
40: R22 Summary of Significant Accounting Policies HTML 150K
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41: R23 Summary of Significant Accounting Policies HTML 123K
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42: R24 Supplemental Disclosures of Cash Flow Information HTML 50K
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Employee Benefits (Tables)
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52: R34 Guarantor Subsidiaries (Tables) HTML 394K
53: R35 Summary of Significant Accounting Policies - HTML 48K
Additional Information (Detail)
54: R36 Summary of Significant Accounting Policies - HTML 44K
Summary of Accounts Receivable (Detail)
55: R37 Summary of Significant Accounting Policies - Net HTML 54K
Capitalized Costs and Associated Accumulated
Depreciation, Depletion & Amortization and Non
Cash Impairments (Detail)
56: R38 Summary of Significant Accounting Policies - HTML 45K
Non-Cash Impairment Charges, Included within
Impairment, Dry Hole Costs and Abandonment Expense
in Consolidated Statements of Operations (Detail)
57: R39 Summary of Significant Accounting Policies - HTML 49K
Accounts Payable and Accrued Liabilities (Detail)
58: R40 Summary of Significant Accounting Policies - HTML 50K
Calculation of Basic and Diluted Earnings (Loss)
Per Share (Detail)
59: R41 Supplemental Disclosures of Cash Flow Information HTML 45K
- Supplemental Cash Flow Information (Detail)
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61: R43 Long-Term Debt - Outstanding Debt (Detail) HTML 73K
62: R44 Long-Term Debt - Additional Information (Detail) HTML 137K
63: R45 Long-Term Debt - Cash and Non-Cash Portion of HTML 46K
Interest Expense Related to Long Term Debt
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64: R46 Asset Retirement Obligations - Schedule of Asset HTML 52K
Retirement Obligations (Detail)
65: R47 Fair Value Measurements - Balance Sheet Grouping HTML 67K
(Detail)
66: R48 Fair Value Measurements - Nonrecurring (Details) HTML 67K
67: R49 Fair Value Measurements - Additional Information HTML 52K
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68: R50 Derivative Instruments - Fair Value Amounts of HTML 64K
Derivative Instruments (Detail)
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Hedging Volume (Detail)
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71: R53 Income Taxes - Expense for Income Taxes (Detail) HTML 45K
72: R54 Income Taxes - Reconciliation of Actual Income Tax HTML 59K
Expense (Detail)
73: R55 Income Taxes - Components of Deferred Tax Assets HTML 84K
and Deferred Tax Liabilities (Detail)
74: R56 Stockholders' Equity - Additional Information HTML 73K
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75: R57 Stockholders' Equity - Schedule of Stockholders HTML 67K
Equity (Detail)
76: R58 Equity Incentive Compensation Plans and Other HTML 165K
Employee Benefits - Additional Information
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Employee Benefits - Non-Cash Stock-Based
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Employee Benefits - Summary of Share-Based Option
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Employee Benefits - Summary of Nonvested Equity
Shares of Common Stock (Detail)
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Employee Benefits - Summary of Nonvested Equity
Shares of Common Stock Issued for Payment of
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Employee Benefits - Summary of Nonvested
Performance-based Cash Units (Details)
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Employee Benefits - Summary of Nonvested
Performance-Based Equity Shares of Common Stock
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Employee Benefits - Deferred Compensation
Liability (Detail)
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Employee Benefits - Deferred Compensation
Investment Assets (Detail)
85: R67 Significant Customers and Other Concentrations - HTML 36K
Additional Information (Detail)
86: R68 Commitments and Contingencies - Additional HTML 39K
Information (Detail)
87: R69 Commitments and Contingencies - Schedule of HTML 39K
Aggregate Undiscounted Minimum Future Lease
Payments (Detail)
88: R70 Commitments and Contingencies - Gross Future HTML 40K
Minimum Transportation Demand and Firm Processing
Charges (Detail)
89: R71 Commitments and Contingencies - Future Minimum HTML 46K
Annual Payments under Drilling, Lease and Other
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90: R72 Guarantor Subsidiaries - Additional Information HTML 39K
(Detail)
91: R73 Guarantor Subsidiaries - Schedule of Condensed HTML 98K
Consolidating Balance Sheets (Detail)
92: R74 Guarantor Subsidiaries - Schedule of Condensed HTML 73K
Consolidating Statements of Operations (Detail)
93: R75 Guarantor Subsidiaries - Schedule of Condensed HTML 50K
Consolidating Statements of Comprehensive Income
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Consolidating Statements of Cash Flows (Detail)
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(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 ž 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 ž 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. ž 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). ž 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. ž
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.
Large accelerated filer
o
Accelerated filer
ž
Non-accelerated
filer
o (Do not check if a smaller reporting company)
Smaller reporting company
o
Emerging growth company
o
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 ž 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).
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.
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.
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
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.
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.
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, Colorado80202, and the telephone number at that address is (303) 293-9100.
We maintain a website at the address http://www.billbarrettcorp.com. We are not including the information contained on our website as part of, or incorporating it by reference into, this report. We make available free of charge through our website
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC via EDGAR and posted at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines and the charters of our Audit Committee, Compensation Committee, Reserves and EHS Committee and Nominating and Corporate Governance Committee are posted on our website and are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 1099 18th Street, Suite 2300,
Denver, Colorado80202. 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.
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.
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.
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 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
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.
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
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
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
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.
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.
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.
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
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;
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
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
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
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
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;
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;
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.
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;
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
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.
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:
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
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.
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.
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."
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.
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.
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.
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.
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.
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.
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
uncertainties. See the "Cautionary Note Regarding Forward-Looking
Statements" at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in "Items 1 and 2. Business and Properties - Business - Operations - Environmental Matters and Regulation;""Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry;" and "Item 1A. Risk Factors" above, all of which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.
Overview
We
develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.
We 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.
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.
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.
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.
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.
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 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.
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.
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%
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:
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:
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,
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.
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:
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:
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 $1.4 million. For the year ended December 31, 2016, we recorded a full valuation allowance against our deferred tax assets, reducing our effective tax rate to zero. In regard to the valuation allowance recorded against our deferred tax asset balance, we
considered all available evidence in assessing the need for a valuation allowance. Such evidence included the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. Additionally, for both the 2017 and 2016 periods, our effective tax rate differs from the federal statutory rate as a result of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as the effect of state income taxes.
The following table sets forth selected operating data for the periods indicated:
Year
Ended December 31,
Increase (Decrease)
2016
2015
Amount
Percent
($ 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.
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:
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:
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:
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:
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
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.
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:
Acquisitions of proved and unproved properties and other real estate
$
20.4
$
5.6
$
7.7
Drilling, development,
exploration and exploitation of oil and natural gas properties
226.9
86.3
264.3
Gathering and compression facilities
11.9
5.3
11.2
Geologic
and geophysical costs
0.5
—
2.9
Furniture, fixtures and equipment
1.0
1.1
1.3
Total
(1)
$
260.7
$
98.3
$
287.4
(1)
Includes
exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $0.5 million, $4.1 million and $3.0 million for the years ended December 31, 2017, 2016 and 2015, respectively.
Capital expenditures for acquisitions of proved and unproved properties and other real estate were $20.4 million for the year ended December 31, 2017. This was primarily related to acquisitions
of unproved properties in the DJ Basin. The increase in drilling, development, exploration and exploitation of oil and natural gas properties to $226.9 million for the year ended December 31, 2017 from $86.3 million for the year ended December 31, 2016 primarily related to an increase in development drilling and completion activities within the DJ Basin as a result of increased oil and gas commodity prices. Capital expenditures for the year ended December 31, 2017 exclude any amounts associated with the pending Merger with Fifth Creek.
Capital
expenditures for acquisitions of proved and unproved properties and other real estate were $5.6 million for the year ended December 31, 2016. This was primarily related to our acquisitions of proved and unproved properties in the DJ Basin. The decrease in drilling, development, exploration and exploitation of oil and natural gas properties to $86.3 million from $264.3 million for the year ended December 31, 2015 primarily related to a decrease in development drilling and completion activities within the DJ and Uinta Basins as a result of lower oil and gas commodity prices.
Our
current estimated capital expenditure budget for the quarter ended March 31, 2018 is $80.0 million to $90.0 million. Following the completion of the Merger, we will update the full year 2018 capital budget to take into account the expanded scope of our operations and other relevant factors. The budget includes facilities costs and excludes acquisitions. We may adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil, natural gas and NGL prices decline to below acceptable levels or costs increase above acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. We would generally do this by prioritizing capital projects
to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow.
We believe that we have sufficient available liquidity with available cash on hand, cash under the Amended Credit Facility and cash flow from operations to fund our 2018 capital expenditures under both our current budget and, although it has not yet been finalized, the revised budget we will adopt following the completion of the Merger. Future cash flows are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.
Financing
Activities
Merger Financing. On December 4, 2017, we entered into the Merger Agreement with Fifth Creek. At the closing of the Merger, New Parent will issue 100 million shares of its common stock to Holdings. In addition, New Parent will be required to pay off Fifth Creek's line of credit in an amount up to $54.0 million, which we plan to pay in full with cash on hand at closing. See "Items 1. and 2. Business and Properties - Business - Significant Business Developments - Pending Merger with Fifth Creek Operating Company, LLC" for additional information.
Equity Offerings. 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 the 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 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.
Redemptions and Issuances. On April 28, 2017, we issued $275.0 million in aggregate principal amount of 8.75% Senior Notes due June 15, 2025 at par. On May 30, 2017, we redeemed all $315.3 million of our outstanding 7.625% Senior Notes
and $0.6 million of Convertible Notes with cash on hand and proceeds from the issuance of our 8.75% Senior Notes. Due to the redemption of the Convertible Notes and the 7.625% Senior Notes, we recognized a $7.9 million loss on extinguishment of debt on the Consolidated Statement of Operations for the year ended December 31, 2017. See Note 5 for additional information.
Amended Credit Facility. There were no borrowings under the Amended Credit Facility in 2017 or 2016. The lenders conducted an interim review of our DJ Basin properties and, upon the disposition of our remaining Uinta Basin properties in December 2017, the lenders waived their right to reduce our $300.0 million borrowing base. While there can be no guarantees, we anticipate that completion of the
Merger and the resulting increase in proved reserves, along with the development of our properties since prior re-determinations, will have a positive effect on the borrowing base. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by our lenders, as well as any other outstanding debt. Lower commodity prices could result in a decreased borrowing base.
We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on the 2018 budget at current commodity prices.
The
Convertible Notes were redeemed on May 30, 2017.
(2)
The 7.625% Senior Notes were redeemed on May 30, 2017.
(3)
The current portion of long-term debt as of December 31, 2017 and 2016 includes the current portion of the Lease Financing
Obligation.
(4)
See Note 5 for additional information.
Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody's Investor Services and Standard & Poor's Rating Services currently rate our 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility,
the 7.0% Senior Notes or the 8.75% Senior Notes. However, our
ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.
Contractual Obligations. A summary of our contractual obligations as of and subsequent to December 31, 2017 is provided in the following table:
Payments
Due By Year
Year 1
Year 2
Year 3
Year 4
Year 5
Thereafter
Total
(in
thousands)
Notes payable (1)
$
184
$
—
$
—
$
—
$
—
$
—
$
184
7.0%
Senior Notes (2)
24,500
24,500
24,500
24,500
374,500
—
472,500
8.75%
Senior Notes (3)
24,063
24,063
24,063
24,063
24,063
335,154
455,469
Lease
Financing Obligation (4)
537
1,869
—
—
—
—
2,406
Office
and office equipment leases and other (5)
3,668
1,149
191
8
—
—
5,016
Firm
transportation agreements (6)
18,556
18,691
18,691
10,902
—
—
66,840
Asset
retirement obligations (7)
1,489
1,175
1,292
1,527
1,176
10,927
17,586
Derivative
liability (8)
20,940
4,118
—
—
—
—
25,058
Total
$
93,937
$
75,565
$
68,737
$
61,000
$
399,739
$
346,081
$
1,045,059
(1)
Notes
payable includes interest on a $26.0 million letter of credit that accrues at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term for the letter of credit is April 30, 2018. There is currently no balance outstanding under our Amended Credit Facility due April 9, 2020.
(2)
On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. On December 15, 2017, we completed an exchange of $50.0 million in principal of the notes for shares of our common stock, reducing our aggregate
principal balance to $350.0 million. We are obligated to make annual interest payments through maturity on October 15, 2022 equal to $24.5 million. See Note 5 to the accompanying financial statements for additional information.
(3)
On April 28, 2017, we issued $275.0 million aggregate principal amount of 8.75% Senior Notes. We are obligated to make annual interest payments through maturity on June 15, 2025 equal to $24.1 million. See Note 5 to the accompanying financial statements for additional information.
(4)
The
Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component.
(5)
The lease for our principal offices in Denver extends through March 2019.
(6)
We have entered into contracts that provide firm transportation capacity on pipeline systems. The contracts
require us to pay monthly transportation demand charges regardless of the amount of gas we deliver to the pipeline.
(7)
Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
(8)
Derivative liabilities represent the net fair value for oil, gas and NGL commodity
derivatives presented as liabilities in our Consolidated Balance Sheets as of December 31, 2017. The ultimate settlement amounts are unknown because they are subject to continuing market fluctuations. See "Critical Accounting Policies and Estimates" below for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements as of December 31, 2017.
Trends
and Uncertainties
Regulatory Trends
Our future Rockies operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits. The regulatory environment continues to become more restrictive, which limits our ability to, and increases the costs of, conducting our operations. Areas in which we operate are subject to federal, state and local regulations. Additional and more restrictive regulations have been seen at each of these governmental levels recently and there are initiatives underway to implement additional regulations and prohibitions on oil and gas activities. New rules may further impact our ability to obtain drilling permits and other required approvals in a timely manner and/or increase the costs of such
permits or approvals. This may create substantial uncertainty about our production and capital expenditure targets. Efforts related to climate change organized around a "keep it in the ground" message have gained traction in New York and other coastal states, as well as internationally, notably in France and Germany.
Federal. Federal leases make up a significant portion of our leaseholds. At the federal level, policies have been implemented that have resulted in a more restrictive regulatory environment for oil and gas activities on public lands. Leasing of Federal lands has declined along with policy directives that require additional analysis prior to leasing federal lands. Litigation seeking to halt exploration and development activities is pervasive. Litigation
will likely be supplemented by civil disobedience - witness the Dakota Access Pipeline protests.
State. We also are experiencing more strict regulation of oil and gas activities at the state level. The Colorado Oil & Gas Conservation Commission ("COGCC") passed rules in 2016 that: (i) increase advance consultation requirements with local governments when large scale oil and gas facilities are proposed in "urban mitigation areas" (generally within 1000' feet of subdivisions, schools, hospitals and other public facilities) and (ii) registration with local governments and provision of development plans to municipalities upon request. We do not anticipate significant disruption to our activities from these new rules given the rural nature of the majority of our leasehold (see discussion below under Local).
Over
the past several years, numerous other rules and policies have been imposed by the COGCC requiring disclosure of chemicals used in hydraulic fracturing, ground water monitoring, increased setbacks from occupied structures and existing wells, and strengthened enforcement, including increases in mandatory monetary penalties for certain violations. In August 2017, Colorado Governor John Hickenlooper announced seven policy initiatives developed during the Colorado's review of oil and gas operations. One policy initiative resulting from Colorado's review is a strengthening of COGCC's flowline regulations and requirements. Potential regulations within the proposed rule include increased registration requirements, flowline design requirements, integrity management requirements, leak detection programs and requirements for abandoned flowlines. The rulemaking is ongoing and a final rule is expected in 2018. As discussed in - "Items 1 and 2. Business and Properties - Operations
- Environmental Matters and Regulation", Colorado regulators also promulgated new, statewide air emissions regulations in 2014 and 2017 that are more stringent than federal requirements. Colorado continues to look at air emissions from the oil and natural gas sector and additional regulations are probable with respect to the Colorado ozone non-attainment standard. Other states, and the EPA, have considered Colorado's air quality rules, including the most recent rules governing methane emissions, as potential models for additional regulation of the oil and natural gas sector.
In combination, these new state rules and policies could impose additional costs on our operations, including enforcement penalties, delay permitting, and potentially impact profitability.
Local. Counties
and municipalities regulate oil and gas activities primarily through local land use rules. Weld County, Colorado, the focus of nearly all of our current development activities, recently adopted an ordinance that requires permitting of essentially all oil and gas operations and is currently considering new pipeline regulations. These changes have the potential to add 60-90 days of delay and may expose our development activities to a new level of political opposition. We expect additional attempts to regulate activities related to oil and gas operations by local governments, including moratoria or bans on hydraulic fracturing, despite 2016 decisions by the Colorado Supreme Court overturning such measures adopted by two municipalities.
Hydraulic Fracturing. The well completion technique known as hydraulic fracturing to stimulate production of natural gas
and oil has come under increased scrutiny by the environmental community, and local, state, and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate oil and natural gas production. We use this completion technique on substantially all our wells. A more comprehensive discussion of potential risks and trends related to hydraulic fracturing is contained above in Items 1 and 2. Business Properties - Operations - Environmental Matters and Regulations. Although it is not possible at this time to predict the final outcome of any proposed legislation, or potential regulatory or policy developments regarding hydraulic fracturing, any new restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions and
could lead to our inability to access, develop, and record natural gas and oil reserves in the future.
Air Quality Regulation. The regulation of air emissions from the oil and natural gas sector continues to be a significant focus for policy makers and regulators at all levels-federal, tribal, state, and local-as well as environmental groups. A more comprehensive discussion of government regulation and potential risks related to air emissions from our operations is included above in "Items 1 and 2. Business and Properties - Operations - Environmental Matters and Regulation". New or more stringent policies, rules, or regulations governing air emissions from the oil and natural gas sector could result in our inability to obtain permits necessary to construct and operate new facilities or operate existing facilities. In addition, even if we are able
to obtain
necessary permits, such new requirements could substantially increase our operating expenses and reduce our profits or make certain operations uneconomic. Both EPA, regionally, and Colorado have stepped up inspection and enforcement activities. The Company has received initial and supplemental EPA "Section 114" mandatory information directives, usually a precursor to an enforcement proceeding, as well as parallel "compliance advisories" from the Colorado Department of Public Health and Environment. We have engaged qualified consultants and
legal counsel to respond to these air quality initiatives and, at the end of 2017, were engaged in settlement discussions. However, the outcome is unclear and could result in assessed penalties and related compliance costs. While we have redesigned our new production facilities to dramatically reduce air emissions, regulatory demands to redesign or retrofit legacy facilities are possible.
Potential Impacts of Regulatory Trends. The increase in regulatory burdens and potential for continued lawsuits seeking to block activities as described above is likely to cause delays to our planned activities and could prevent some of these activities. This is expected to increase our costs and could result in lower production and reserves as our properties naturally decline without replacement production and reserves from new wells in addition to a reduction in the
value of our current leases.
For additional detail, see "Items 1 and 2. Business and Properties - Operations - Environmental Matters and Regulation" and "Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry".
Declining Commodity Prices. The severe decline in oil prices that occurred in 2014 and 2015 increased the volatility and amplitude of the other risks facing us as described in this report and had an impact on 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.
The sustained decline in commodity prices may also expose us to unexpected liability for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. If such third parties become unable to fulfill their contract obligations to the Company as provided for in purchase and sale agreements, regulatory agencies and landowners may demand that we perform such activities. Recent case law in Wyoming has increased such exposure for companies that have divested assets to no longer viable entities, and we have received demands from the Bureau of Land Management and a several large ranches to plug and abandon wells, and conduct associated reclamation,
on properties we no longer own. The Company recognized $0.3 million associated with these obligations in other operating expenses in the Consolidated Statement of Operations for the year ended December 31, 2017.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements
requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting
policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.
Oil and Gas Properties
Our oil, natural gas and NGL exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs
of drilling the well are charged to expense and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized and are included within additions to oil and gas properties and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether proved reserves are added or not. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed
54
quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production
could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well, and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use.
The application of the successful efforts method of accounting
requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. In addition to development on exploratory wells, we may drill scientific wells that are only used for data gathering purposes. The costs associated with these scientific wells are expensed as incurred as exploration expense. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience.
Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss
is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.
Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. 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
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, 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.
55
Our
investment in producing oil and natural gas properties includes an estimate of the future costs associated with dismantlement, abandonment and restoration of our properties. The present value of the estimated future costs to dismantle, abandon and restore a well location are added to the capitalized costs of our oil and gas properties and recorded as a long-term liability. The capitalized cost is included in the oil and natural gas property costs that are depleted over the life of the assets.
The provision for depletion of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves,
which incorporate assumptions regarding future development and abandonment costs as well as our level of capital spending. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.
Oil and Gas Reserve Quantities
Our estimate of proved reserves is based on the quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially
recoverable in future years from known reservoirs under existing economic and operating conditions. Our proved reserves estimates are audited on a well-by-well basis by an independent third party engineering firm. In the aggregate, the independent third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates as of December 31, 2017.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserves estimates. We prepare our reserves estimates, and the projected cash flows derived from these reserves estimates, in accordance with SEC guidelines. Our independent third party engineering firm adheres
to the same guidelines when auditing our reserve reports. The accuracy of our reserves estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the reserves estimates.
The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserves estimates may occur from
time to time. Although every reasonable effort is made to ensure that the reported reserves estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statements. As such, reserves estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
Please refer to the reserve disclosures in "Items 1 and 2 - Business and Properties" for further detail on reserves data.
Revenue Recognition
Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable
price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. We use the sales method to account for gas and NGL imbalances. Under this method, revenues are recorded on the basis of gas and NGLs actually sold by us. In addition, we record revenues for our share of gas and NGLs sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. We also reduce our revenues for other owners' gas and NGLs sold by us that cannot be volumetrically balanced in the future due to insufficient remaining reserves. Our remaining over- and under- produced gas and NGL balancing positions are taken into account in determining our proved oil, gas and NGL reserves.
Derivative Instruments and Hedging Activities
We
use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. These derivative instruments are recorded at fair market value and included in the balance sheet 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
56
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.
The estimates of the fair values of our derivative instruments require substantial judgment. These values are based upon, among other things, futures prices, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
Income Taxes and Uncertain Tax Positions
Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods
for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes are also recognized for net operating loss carry forwards and tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statement and income tax reporting. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider estimated future taxable income in making such assessments. Numerous judgments and assumptions are inherent
in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). There can be no assurance that facts and circumstances will not materially change and require us to adjust deferred tax asset valuation allowances in the future.
Accounting guidance for recognizing and measuring uncertain tax positions prescribes a more likely than not recognition threshold that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. Based on this guidance, we regularly analyze tax positions taken or expected to be taken in a tax return based on the threshold prescribed. Tax positions that do not meet or exceed
this threshold are considered uncertain tax positions. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. We currently do not have any uncertain tax positions recorded as of December 31, 2017.
We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine the liability no longer applies. Conversely, we record additional tax charges in a period in which we determine that a recorded tax liability is less than we expect
the ultimate assessment to be.
New Accounting Pronouncements
For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to the Summary of Significant Accounting Policies (in Note 2) of the Notes to Consolidated Financial Statements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential
exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our primary market risk exposure is to the prices we receive for our production. Commodity pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing
for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily
production and our derivative contracts in place for the year ended December 31, 2017, our income before
taxes would have decreased by approximately $1.4 million for each $1.00 per barrel decrease in crude oil prices, $0.5 million for each $0.10 decrease per MMBtu in natural gas prices and $1.2 million for each $1.00 per barrel decrease in NGL prices.
We routinely enter into commodity hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty. These commodity hedging activities are intended to support oil, natural gas and NGL
prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations. We do not enter into any market risk sensitive instruments for trading purposes.
As of February 6, 2018, we have financial derivative instruments related to oil, natural gas and NGL volumes in place for the following periods indicated. Further detail of these hedges is summarized in the table presented under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities".
For
the Year 2018
For the Year 2019
Derivative Volumes
Weighted Average Price
Derivative Volumes
Weighted Average Price
Oil (Bbls)
3,674,500
$
53.55
1,914,750
$
54.17
Natural
Gas (MMbtu)
1,825,000
2.68
—
—
Item 8. Financial
Statements and Supplementary Data.
The information required by this item is included below in "Item 15. Exhibits, Financial Statement Schedules".
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures. As of December 31,
2017, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Exchange Act. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective as of December 31, 2017.
Management's Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining internal control over financial reporting. Our internal control over financial reporting is a process designed
under the supervision of our principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Management has assessed the effectiveness of our internal control over financial reporting. In making this assessment, it used the criteria set forth by the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment we have concluded that, as of December 31, 2017, our internal control over financial reporting is effective.
Our
independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. That report is set forth below.
Changes in Internal Controls. There was no change in our internal control over financial reporting during the fourth fiscal quarter of 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
58
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of Bill Barrett Corporation
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Bill Barrett Corporation and subsidiaries (the "Company") as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the
Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2017, of the Company and our report dated February 27, 2018, expressed an unqualified opinion on those financial statements.
Basis
for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition
and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts
and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
The
following table provides aggregate information presented as of December 31, 2017 with respect to all compensation plans under which equity securities are authorized for issuance.
(a)
(b)
(c)
Plan
Category
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
Weighted Averaged
Exercise Price of
Outstanding
Options, Warrants
and Rights (1)
Number
of Securities
Remaining Available
for Future Issuance
(Excluding Securities
Reflected in Column (a))
Equity compensation plans approved by shareholders
199,123
$
31.42
1,811,125
Equity
compensation plans not approved by shareholders
—
—
—
Total
199,123
$
31.42
1,811,125
(1)
The
weighted average exercise price relates to the 199,123 outstanding options included in column (a).
Item 13. Certain Relationships and Related Transactions and Director Independence.
Consolidated
Statements of Stockholders' Equity for the years ended December 31, 2017, 2016 and 2015
72
Notes to Consolidated Financial Statements
73
All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and
Notes thereto.
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors of Bill Barrett Corporation
Opinion on the Financial
Statements
We have audited the accompanying consolidated balance sheets of Bill Barrett Corporation and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders' equity for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all
material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with the accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2018, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess
the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Accounts receivable, net of allowance for doubtful accounts
51,415
32,837
Derivative
assets
—
8,398
Prepayments and other current assets
1,782
1,376
Total current assets
367,663
318,452
Property
and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties
1,361,168
1,539,373
Unproved oil and gas properties, excluded from amortization
84,676
58,830
Furniture,
equipment and other
17,899
23,636
1,463,743
1,621,839
Accumulated depreciation, depletion, amortization and impairment
(444,863
)
(559,690
)
Total
property and equipment, net
1,018,880
1,062,149
Deferred income tax asset
—
1,587
Deferred financing costs and other noncurrent assets
4,163
3,153
Total
$
1,390,706
$
1,385,341
Liabilities
and Stockholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities
$
84,055
$
49,447
Amounts
payable to oil and gas property owners
16,594
6,192
Production taxes payable
26,876
22,992
Derivative liabilities
20,940
4,346
Deferred
income taxes
—
1,587
Current portion of long-term debt
469
454
Total current liabilities
148,934
85,018
Long-term
debt, net of debt issuance costs
617,744
711,808
Asset retirement obligations
16,097
10,703
Derivatives and other noncurrent liabilities
9,377
6,269
Commitments
and contingencies (Note 13)
Stockholders' equity:
Common stock, $0.001 par value; authorized 300,000,000 and 150,000,000 shares at December 31, 2017 and 2016; 110,363,539
and 75,721,360 shares issued and outstanding at December 31, 2017 and 2016, respectively, with 1,394,868 and 1,325,714 shares subject to restrictions, respectively
Cumulative effect of accounting change is related to the adoption of Accounting Standards Update 2016-09. See Note 2 of the Consolidated Financial Statements for further detail on the adoption of this accounting standard.
Bill Barrett Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the "Company") is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas
and NGLs. Since its inception in January 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.
2. Summary of Significant Accounting Policies
Basis of Presentation. The accompanying Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All intercompany accounts and transactions have
been eliminated in consolidation.
Use of Estimates. In the course of preparing the Company's financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.
Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil, natural gas and NGL reserves used in calculating
depreciation, depletion and amortization ("DD&A"), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining asset retirement obligations, the timing of dry hole costs, impairments of proved and unproved properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based payment awards.
Cash and Cash Equivalents. The Company considers all highly liquid investments with a remaining maturity of three months or less when purchased to be cash equivalents.
Short-term
Investments. Short-term investments have maturities of more than three months and less than one year.
Accounts Receivable. Accounts receivable is comprised of the following:
Oil
and Gas Properties. The Company's oil, gas and NGL exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized and are included within additions to oil and gas properties and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether proved reserves are added
or not. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.
Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization
rate. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.
Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. 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.
Materials and supplies consist
primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market value.
The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company's oil, natural gas and NGL producing activities:
Total unproved oil and gas properties, excluded from amortization
$
84,676
$
58,830
Accumulated
depreciation, depletion, amortization and impairment
(433,234
)
(543,154
)
Total oil and gas properties, net
$
1,012,610
$
1,055,049
All
exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. As of December 31, 2017 and 2016, there were no exploratory well costs
that had been capitalized for a period greater than one year since the completion of drilling.
The Company reviews proved oil and gas properties on a field-by-field basis 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 the Company concludes the carrying value may not be recoverable, the Company estimates the expected undiscounted future net cash flows of its oil and gas properties based on the Company's best estimate
of development plans, future production, commodity pricing, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. The Company compares 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 proved oil and gas properties, no impairment is taken. If the carrying value of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. The Company
does not believe that the undiscounted future net cash flows of its oil and gas properties represent the applicable market value. The factors used to determine fair value 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 expected cash flows projected.
Oil
and gas properties are also 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, the Company utilizes the income valuation technique which involves calculating the present value of future revenues, 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.
The Company recognized non-cash impairment charges, which were included within impairment, dry hole costs and abandonment expense in the Consolidated Statements of Operations, as follows:
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.
(3)
Due to the decline in oil prices, the Company recognized a non-cash impairment charge associated with the Company's Uinta Oil Program proved and unproved properties for the year ended December 31, 2015.
The provision for DD&A
of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Estimated future dismantlement, restoration and abandonment costs are taken into consideration by this calculation.
Accounts Payable and Accrued Liabilities. Accounts payable and accrued liabilities are comprised of the following:
Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Environmental liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Recent case law in Wyoming has exposed us to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. If such third parties become unable to fulfill their contract obligations to the Company as provided for in purchase and sale agreements, regulatory agencies
and landowners may demand that the Company perform such activities. The Company recognized $0.7 million and $0.3 million associated with these obligations in other operating expenses in the Consolidated Statement of Operations for the years ended December 31, 2017 and 2016, respectively.
Revenue Recognition. Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable
price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. The Company uses the sales method to account for gas and NGL imbalances. Under this method, revenues are recorded on the basis of gas and NGLs actually sold by the Company. In addition, the Company records revenues for its share of gas and NGLs sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenues for other owners' gas and NGLs sold by the
Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's remaining over- and under- produced gas and NGLs balancing positions are taken into account in determining the Company's proved oil, gas and NGL reserves. Imbalances at December 31, 2017 and 2016 were not material.
Derivative Instruments and Hedging Activities. The Company periodically uses
derivative financial instruments to achieve a more predictable cash flow from its oil, natural gas and NGL sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities.
Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist
of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes
also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates. Deferred tax assets are regularly reviewed, considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, taxable strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine whether it is more likely than not that the deferred tax asset will be realized.
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The
Company does not have any uncertain tax positions recorded as of December 31, 2017 or 2016.
Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive
securities for the diluted net income per common share calculations consist of nonvested equity shares of common stock and in-the-money outstanding stock options to purchase the Company's common stock. As the Company was in a net loss position, all potentially dilutive securities were anti-dilutive for the years ended December 31, 2017, 2016 and 2015.
The following table sets forth the calculation of basic and diluted net income (loss) per share:
Basic weighted-average common shares outstanding
in period
76,859
55,384
48,303
Add dilutive effects of stock options and nonvested shares of common stock
—
—
—
Diluted
weighted-average common shares outstanding in period
76,859
55,384
48,303
Basic net income (loss) per common share
$
(1.80
)
$
(3.08
)
$
(10.10
)
Diluted
net income (loss) per common share
$
(1.80
)
$
(3.08
)
$
(10.10
)
Industry Segment and Geographic Information. The
Company operates in one industry segment, which is the development and production of crude oil, natural gas and NGLs, and all of the Company's operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.
New Accounting Pronouncements. In May 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-09, Stock Compensation-Scope of Modification Accounting. The objective of this update is to provide clarity and reduce both diversity in practice and cost and complexity when applying a change to the terms
or conditions of a share-based payment award. ASU 2017-09 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.
In January 2017, the FASB issued ASU 2017-01, Business Combinations: Clarifying the definition of a business. The objective of this update is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or
disposals) of assets or businesses. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments. The objective of this update is to address eight specific cash flow issues in order to reduce the existing diversity in practice. ASU 2016-15 is effective for the annual periods beginning after December
15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. The objective of this update is to simplify the current guidance for stock compensation. The areas for simplification involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 was effective for annual
periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted effective January 1, 2017 and did not have a significant impact on the Company's disclosures or financial statements. As of January 1, 2017, the Company did not have excess tax benefits associated with its stock compensation and therefore there was no tax impact upon adoption of this standard. In addition, the employee taxes paid on the statement of cash flows when shares were withheld for taxes were already classified as a financing activity; therefore, there was no cash flow statement impact upon adoption of this standard. The
Company elected to account for forfeitures as they occur as opposed to estimating the number of awards that are expected to vest. Per ASU 2016-09, the election is considered a change in accounting principle, with the cumulative effect of the change reported as an adjustment to the beginning equity balance. The Company reported an increase to accumulated deficit and additional paid in capital ("APIC") of $0.2 million related to equity award compensation and an increase to accumulated deficit and derivative and other noncurrent liabilities of $0.3 million related to liability award compensation. The cumulative effect of accounting change is reported in the Consolidated Statement of Stockholders' Equity.
In
February 2016, the FASB issued ASU 2016-02, Leases. The objective of this update is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The Company has performed an initial assessment by compiling and analyzing contracts and leasing arrangements that may be affected. The Company is still evaluating the impact of adopting this standard.
In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The objective of this update is to require deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. ASU 2015-17 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted January 1, 2017 on a prospective basis and did not have a significant impact on the Company's disclosures and financial statements. Prior periods were not retrospectively adjusted.
In
May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20, which provided additional implementation guidance and deferred the effective date of ASU 2014-09. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The standard will be adopted using the modified retrospective transition method, effective January 1, 2018. The Company has performed an assessment of its current existing
revenue contracts and has implemented additional control procedures. On a prospective basis, the Company will net its gathering, transportation and processing expenses (not already presented on a net basis) against its oil, gas, and NGL production revenues. However, the cash flow and timing of the Company's revenue will not change, therefore, there will be no impact to the Company's net income (loss) or net income (loss) per common share. The standard will also require expanded footnote disclosure.
3.
Supplemental Disclosures of Cash Flow Information
Supplemental
disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties
43,980
23,944
33,805
Change
in asset retirement obligations, net of disposals
5,376
(4,799
)
(9,101
)
Fair value of debt exchanged for common stock (1)
48,992
74,400
—
Retirement
of treasury stock
(1,253
)
(1,114
)
(1,173
)
Properties exchanged in non-cash transactions
13,323
—
—
(1)
See
Note 5 for additional information regarding the 2017 Debt Exchange and the 2016 Debt Exchange.
4. Mergers, Acquisitions, Exchanges and Divestitures
Pending Merger with Fifth Creek Operating Company, LLC
On December 4, 2017, the Company entered into an Agreement and Plan of Merger (the "Merger
Agreement") with Fifth Creek Operating Company, LLC ("Fifth Creek"), Red Rider Holdco, Inc., a wholly owned subsidiary of the Company ("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.
As consideration to the Company's stockholders, each share of the Company's 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 the
Company 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 $54.0 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.
2017 Acquisitions, Exchanges and Divestitures.
On February 28, 2017, the Company acquired acreage in the DJ Basin for $11.6 million, after final closing adjustments. The transaction was considered an asset acquisition and therefore the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired.
The acquisition included $9.1 million and $11.2 million of proved and unevaluated properties, respectively, and asset retirement obligations of $8.7 million.
During the year ended December 31, 2017, the Company completed two acreage exchange transactions to consolidate certain acreage positions in the DJ Basin. Pursuant to the transactions, the Company exchanged leasehold interests in certain proved undeveloped acreage. The Company's future
cash flows are not expected to significantly change as a result of the exchange transactions, therefore, the non-monetary exchanges were measured based on the carrying values and not on the fair values of the assets exchanged.
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. During the quarter ended December 31, 2017, the Company recognized proved property impairment of $37.9 million with respect to these properties in the Consolidated Statement of Operations. The carrying amounts by major asset class within the disposal group for the Uinta Basin are summarized below (in thousands):
Assets:
Proved
oil and gas properties
$
410,028
Unproved oil and gas properties, excluded from amortization
379
Furniture, equipment and other
1,593
Accumulated
depreciation, depletion, amortization and impairment
(304,939
)
Total assets
107,061
Liabilities:
Asset retirement obligations
4,773
Total
liabilities
4,773
Net assets
$
102,288
2016 Divestitures.
On July 14, 2016, the Company sold
certain non-core assets in the Uinta Basin. The Company received $27.8 million in cash proceeds, after 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. Assets sold included $30.6 million in proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment, and $2.0 million in unproved oil and gas properties. Liabilities sold included $4.8
million of asset retirement obligations. The transaction was accounted for as a cost recovery. Therefore, no gain or loss was recognized.
2015 Divestitures.
On February 27, 2015, the Company sold its remaining Powder River Basin assets. The Company received $9.3 million in cash proceeds, after final closing adjustments. These assets were classified as held for sale in the Consolidated Balance Sheet as
of December 31, 2014. Upon the classification as held for sale, the assets were analyzed relative to their fair market values. The Company recognized proved and unproved property impairments of $14.8 million and $6.4 million, respectively, during the year ended December 31, 2014, with respect to these properties.
Also during the year ended December 31, 2015, the Company sold certain non-core
assets located in the DJ Basin in two separate transactions that closed on October 21, 2015 and November 30, 2015, respectively. In the aggregate, these non-core assets included interests in legacy vertical producing wells and were sold for cash proceeds of $29.5 million, after final closing adjustments.
On November 30, 2015, the Company sold certain non-core assets located in the Uinta Basin, which included interests in producing wells for cash proceeds of $25.3 million, after final closing adjustments.
5.
Long-Term Debt
The Company's outstanding debt is summarized below:
The
Convertible Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the Convertible Notes was approximately $0.5 million as of December 31, 2016 based on reported market trades of these instruments.
(2)
The 7.625% Senior Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the 7.625% Senior Notes was approximately $314.5 million as of December 31,
2016 based on reported market trades of these instruments.
(3)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $356.1 million and $384.5 million as of December 31, 2017 and 2016, respectively, based on reported market trades of these instruments.
(4)
The
aggregate estimated fair value of the 8.75% Senior Notes was approximately $305.3 million as of December 31, 2017 based on reported market trades of these instruments.
(5)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.1 million and $2.6 million as of December 31, 2017 and 2016,
respectively. As there is no active public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.
(6)
The current portion of long-term debt as of December 31, 2017 and 2016 includes the current portion of the Lease Financing Obligation.
Amended Credit Facility
The
Amended Credit Facility had commitments from 13 lenders and a borrowing base of $300.0 million as of December 31, 2017. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit has been issued under the Amended Credit Facility, which reduced the available borrowing capacity of the Amended Credit Facility as of December 31, 2017 to $274.0 million. There were no borrowings under the Amended Credit Facility in 2017 or 2016.
Interest
rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the unused commitment fee is between 0.375% to 0.5% based on borrowing base utilization.
The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders, based on the collateral value of the
Company's proved reserves that have been mortgaged to the lenders, and is subject to regular re-determinations on or about April 1 and October 1 of each year, as well as following any property sales. The lenders conducted an interim review of the Company's DJ Basin properties and, upon the disposition of the Company's remaining Uinta Basin properties in December 2017, the lenders waived their right to reduce the Company's $300.0 million borrowing base. While there can be no guarantees, the Company anticipates that completion of the Merger and the resulting increase in proved reserves,
along with the development of the Company's properties since prior re-determinations, will have a positive effect on the borrowing base. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the Company's lenders, as well as any other outstanding debt. Lower commodity prices could result in a decreased borrowing base.
The Amended Credit Facility contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied
with all financial covenants since issuance. If the Company fails to comply with the covenants or other terms of any agreements governing the Company's debt, the Company's lenders and holders of the Company's senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect the Company's financial condition. In September 2015, the Company
obtained an amendment to the Amended Credit Facility that replaced the Company's debt-to-EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses) covenant in the facility with a secured debt-to-EBITDAX covenant and an EBITDAX-to-interest covenant through March 31, 2018. There can be no assurance that the Company will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.
5% Convertible Senior Notes Due 2028
On May 30, 2017, the
Company redeemed the $0.6 million of outstanding Convertible Notes with the proceeds of its 8.75% Senior Notes issued on April 28, 2017. See "8.75% Senior Notes due 2025" below for additional information.
7.625% Senior Notes Due 2019
On May 30, 2017, the Company redeemed the $315.3 million of outstanding 7.625% Senior Notes with cash on hand and proceeds from
the issuance of its 8.75% Senior Notes on April 28, 2017. See "8.75% Senior Notes due 2025" for additional information.
Due to the redemption of the Convertible Notes and the 7.625% Senior Notes, the Company recognized a $7.9 million loss on extinguishment of debt on the Consolidated Statement of Operations for the year ended December 31, 2017.
The 7.625% Senior
Notes were issued at $400.0 million in principal amount on September 27, 2011. On June 3, 2016, the Company completed a debt exchange with a holder of the 7.625% Senior Notes (the "2016 Debt Exchange"). The holder exchanged $84.7 million principal amount of the 7.625% Senior Notes for 10,000,000 newly issued shares of the Company's common stock. Based on the fair value of the shares issued, the
Company recognized an $8.7 million gain on extinguishment of debt on the Consolidated Statement of Operations for the year ended December 31, 2016. Following the 2016 Debt Exchange, the remaining aggregate principal amount was $315.3 million, which, as indicated above, was then redeemed on May 30, 2017.
7.0% Senior Notes Due 2022
On March 12, 2012, the Company issued $400.0 million in aggregate principal amount
of 7.0% Senior Notes due October 15, 2022 at par. On December 15, 2017, the Company completed a debt exchange with a holder of the 7.0% Senior Notes (the "2017 Debt Exchange"). The holder exchanged $50.0 million principal amount of the 7.0% Senior Notes for 10,863,000 newly issued shares of the Company's common stock. Based on the fair value of the shares issued, the Company recognized
a $0.3 million loss on extinguishment of debt on the Consolidated Statement of Operations for the year ended December 31, 2017. Following the 2017 Debt Exchange, $350.0 million aggregate principal amount of the 7.0% Senior Notes was outstanding as of December 31, 2017.
The 7.0% Senior Notes mature on October 15, 2022, unless earlier redeemed or purchased by the
Company. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company's other existing and future senior unsecured indebtedness, including the 8.75% Senior Notes.
The 7.0% Senior Notes became redeemable at the
Company's option on October 15, 2017 at a redemption price of 103.500% of the principal amount. The redemption price will decrease to 102.333%, 101.167% and 100.000% of the principal amount in 2018, 2019 and 2022, respectively. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the 8.75% Senior Notes. The 7.0% Senior
Notes include certain covenants that limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance. On December 13, 2017, the Company entered into consent agreements with the holders of a majority of the 7.0% Senior Notes to amend the indenture
governing the 7.0% Senior Notes to, among other things, amend the defined term "Change of Control" in the indenture to provide that the Merger will not constitute a "Change of Control" under the indenture. The Company paid consent fees of $2.50 per $1,000 principal amount, or approximately $1.0 million, related to the 7.0% Senior Notes. The consent fees were reported in long-term debt, net of issuance costs on the Consolidated Balance Sheet as of December
31, 2017 and will be amortized over the remaining term of the 7.0% Senior Notes.
8.75% Senior Notes due 2025
On April 28, 2017, the Company issued $275.0 million in aggregate principal amount of 8.75% Senior Notes due June 15, 2025 at par. Interest is payable in arrears semi-annually on June 15 and December 15 of each year. The 8.75% Senior Notes are senior unsecured obligations and rank equal in right of payment with
all of the Company's other existing and future senior unsecured indebtedness, including the 7.0% Senior Notes.
The 8.75% Senior Notes will become redeemable at the Company's option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of 106.563%, 104.375%, 102.188% and 100.000% of
the principal amount, respectively. Prior to June 15, 2020, the Company may use proceeds of an equity offering to redeem up to 35% of the principal amount at a redemption price of 108.750% of the principal amount. In addition, prior to June 15, 2020, the Company may redeem the notes at a redemption price equal to 100.000% of the principal amount plus a specified "make-whole" premium.
The 8.75% Senior Notes are fully and
unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the 7.0% Senior Notes. The 8.75% Senior Notes include certain covenants that limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends. The Company is currently in compliance with all covenants and has
complied with all covenants since issuance. On December 13, 2017, the Company entered into consent agreements with all of the holders of the 8.75% Senior Notes to amend the indenture governing the 8.75% Senior Notes to, among other things, amend the defined term "Change of Control" in the indenture to provide that the Merger will not constitute a "Change of Control" under such indenture. The
Company paid consent fees of $2.50 per $1,000 principal amount, or approximately $0.7 million, related to the 8.75% Senior Notes. The consent fees were reported in long-term debt, net of issuance costs on the Consolidated Balance Sheet as of December 31, 2017 and will be amortized over the remaining term of the 8.75% Senior Notes.
Nothing in the indentures governing the 7.0% Senior Notes or the 8.75% Senior Notes prohibits
the Company from repurchasing any of the notes from time to time at any price in open market purchases, negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.
Lease Financing Obligation Due 2020
The Company has a lease financing obligation with a balance of $2.3 million as of December 31, 2017 resulting from the Company's sale and subsequent
lease back of certain compressors and related facilities owned by the Company (the "Lease Financing Obligation"). The Lease Financing Obligation expires on August 10, 2020, and the Company has the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option pursuant to which the Company may purchase the equipment for $1.8 million on February 10, 2019. The lease payments related to the equipment are recognized
as principal and interest expense based on a weighted average implicit interest rate of 3.3%. See Note 13 for discussion of aggregate minimum future lease payments.
6. Asset Retirement Obligations
A reconciliation of the Company's asset retirement obligations for the year ended December 31, 2017, 2016 and 2015 is as follows:
Includes $8.7
million associated with properties acquired in the DJ Basin during the year ended December 31, 2017. See Note 4 for additional information regarding this acquisition.
7. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company uses market data or assumptions that market participants
would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2
– Quoted prices are available in active markets for similar assets or liabilities and in non-active markets for identical or similar instruments. Model-derived valuations have inputs that are observable or whose significant value drivers are observable. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 – Pricing inputs include significant inputs that are generally less observable
than objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:
Cash equivalents
– The highly liquid cash equivalents are recorded at fair value. Carrying value approximates fair value, which represents a Level 1 input.
Deferred compensation plan – The Company maintains a non-qualified deferred compensation plan which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in other current and other long-term assets in the Consolidated Balance Sheets. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which
represent Level 1 inputs.
Commodity derivatives – The fair value of crude oil, natural gas and NGL forwards are valued based on an income approach using various assumptions, such as quoted forward prices for commodities and time value factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are, therefore, designated
as Level 2 inputs. The Company utilizes its counterparties' valuations to assess the reasonableness of its own valuations.
The commodity derivatives have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. In addition, the fair value measurement of a liability has been adjusted to reflect the nonperformance risk of the Company.
The following tables set forth by level within the fair value hierarchy the
Company's non-financial assets and liabilities that were measured at fair value on a recurring basis in the Consolidated Balance Sheets.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain
assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
Oil and gas properties – Oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. If an impairment is necessary, the fair value is estimated by using either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique, which involves calculating the present value of future revenues. The present value, net of estimated operating and development costs, is calculated 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, predominantly all of which are designated as Level 3 inputs within the fair value hierarchy.
Information about the impaired assets is as follows:
Amount
represents net book value at the date of assessment.
(2)
See Note 2 for additional information regarding oil and gas property impairments.
(3)
The Uinta Basin properties were sold in December 2017. See Note 4 for additional information regarding the sale of the Uinta Basin properties.
Additional Fair Value Disclosures
Long-term
Debt – Long-term debt is not presented at fair value on the Consolidated Balance Sheets, as it is recorded at carrying value, net of unamortized debt issuance costs. The Company issued the 8.75% Senior Notes on April 28, 2017 and redeemed its 7.625% Senior Notes on May 30, 2017. The fair values of the Company's fixed rate 7.0% Senior Notes and 8.75% Senior Notes totaled $661.4 million as of December 31,
2017. The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $699.0 million as of December 31, 2016. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.
The Company estimated the fair value of the 2017 Debt Exchange and the 2016 Debt Exchange based on the
fair value of the Company's common stock. The fair value of the common stock was based on active market quotes, which represent Level 1 inputs. The Company recognized a $0.3 million loss and an $8.7 million gain on extinguishment of debt on the Consolidated Statements of Operations for the years ended December 31, 2017 and 2016, respectively, as a result of the 2017 Debt Exchange and the 2016 Debt Exchange, respectively. See Note 5 for additional information.
There
is no active, public market for the Amended Credit Facility or Lease Financing Obligation and there was no such market for the Convertible Notes when they were outstanding. The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company's borrowing base utilization. The Amended Credit Facility had a balance of zero as of both December 31, 2017 and 2016. The Convertible Notes were redeemed on May 30, 2017 and had a fair value of $0.5 million as of
December 31, 2016. The Lease Financing Obligation fair values of $2.1 million and $2.6 million as of December 31, 2017 and 2016, respectively, are measured based on market-based parameters of comparable term secured financing instruments. The fair value measurements for the Amended Credit Facility, Convertible Notes and Lease Financing Obligation represent Level 2 inputs.
8. Derivative Instruments
The
Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap contracts related to the sale of a portion of the Company's production. The Company does not enter into derivative instruments for speculative or trading purposes.
In addition to financial contracts,
the Company may at times be party to various physical commodity contracts for the sale of oil, natural gas and NGLs that have varying terms and pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, natural gas and NGL production revenues at the time of settlement.
All derivative instruments, other than those that meet the
normal purchase and normal sale exception, as mentioned above, are recorded at fair value and included on the Consolidated Balance Sheets as assets or liabilities. The following table
summarizes the location, as well as the gross and net fair value amounts of all derivative instruments presented on the Consolidated Balance Sheets as of the dates indicated.
Net Amounts of Assets Presented in the Balance Sheet
(in
thousands)
Derivative assets
$
13,156
$
(4,758
)
(1)
$
8,398
Deferred
financing costs and other noncurrent assets
—
—
—
Total derivative assets
$
13,156
$
(4,758
)
$
8,398
Gross
Amounts of Recognized Liabilities
Gross Amounts Offset in the Balance Sheet
Net Amounts of Liabilities Presented in the Balance Sheet
(in thousands)
Derivative
liabilities
$
(9,104
)
$
4,758
(1)
$
(4,346
)
Derivatives and other noncurrent liabilities
(899
)
—
(899
)
Total
derivative liabilities
$
(10,003
)
$
4,758
$
(5,245
)
(1)
Asset
and liability balances with the same counterparty are presented as a net asset or liability on the Consolidated Balance Sheets.
As of December 31, 2017, the Company had financial instruments in place to hedge the following volumes for the periods indicated:
For
the Year 2018
For the Year 2019
Derivative Volumes
Weighted Average Price
Derivative Volumes
Weighted Average Price
Oil (Bbls)
3,444,500
$
53.01
1,367,250
$
52.85
Natural
Gas (MMbtu)
1,825,000
2.68
—
—
The Company's
derivative financial instruments are generally executed with major financial or commodities trading institutions. The instruments expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company had hedges in place with seven different counterparties as of December 31, 2017. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of non-performance by the counterparties, are substantially smaller. The creditworthiness
of
counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.
It is the Company's 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. The Company's 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. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed the
Company under derivative contracts. Where the counterparty is not a lender under the Company's Amended Credit Facility, the Company may not be able to set-off amounts owed by the Company under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. The Company does not have any derivative balances that are offset by cash collateral.
9.
Income Taxes
The (expense) benefit for income taxes consisted of the following for the periods indicated:
Income
tax (expense) benefit differed from the amounts computed by applying the U.S. federal income tax rate of 35% to pretax income from continuing operations as a result of the following:
Income tax (expense) benefit at the federal statutory rate
$
48,869
$
59,632
$
232,700
State income taxes, net of
federal tax effect
4,030
4,971
19,399
Change in federal tax rate
(64,949
)
—
—
Refundable
AMT credits
1,402
—
—
Nondeductible equity-based compensation
(13,655
)
(64
)
(179
)
Other
permanent items
(37
)
(62
)
(100
)
Change in valuation allowance
(35,684
)
(64,477
)
(74,978
)
Change
in valuation allowance due to TCJA
64,949
—
—
Change in apportioned state tax rates
(1,086
)
—
(74
)
Eliminate
UT jurisdiction NOL's and credits
(2,647
)
—
—
Other, net
210
—
317
Income
tax (expense) benefit
$
1,402
$
—
$
177,085
87
The
tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at December 31, 2017 and 2016 are presented below:
At December 31, 2017, the Company projected approximately $727.4 million of federal tax net operating loss ("NOL") carryforwards
which expire beginning in 2025. At December 31, 2017, the Company had $485.7 million of state NOLs which begin to expire in 2029 and state tax credits of $8.2 million which begin to expire in 2018. As a result of the Merger which we anticipate to close on March 19, 2018, we expect to incur an ownership change and therefore anticipate losing a significant amount of our NOL carryforwards. This will result in a reduction of our deferred tax asset balance related to the NOL carryforward and the associated valuation allowance.
On December
22, 2017, Congress signed into law the Tax Cut and Jobs Act of 2017 ("TCJA"). The TCJA includes significant changes to the U.S. corporate tax systems including a rate reduction from 35% to 21% beginning in January of 2018, the elimination of the corporate alternative minimum tax ("AMT"), the acceleration of depreciation for US tax purposes, limitations on deductibility of interest expense, the elimination of net operating loss carrybacks and limitations on the use of future losses. In accordance with ASC 740, Income Taxes, the impact of a change in tax law is recorded in the period of enactment. Consequently, the Company has recorded a decrease to its net deferred tax assets ("DTA") of $64.9 million
with a corresponding net adjustment to the valuation allowance for the year ended December 31, 2017. The Company also eliminated the $1.4 million DTA for its AMT credits and recorded a noncurrent tax receivable with a corresponding benefit to current income taxes. With respect to these particular aspects of the TCJA and the impacts to the 2017 financial statements,
88
management believes the accounting is substantially complete. As a result of other changes introduced by the TCJA, starting with compensation paid in 2018, Section 162(m) will limit the
Company from deducting compensation, including performance-based compensation, in excess of $1.0 million paid to anyone who, starting in 2018, serves as the Chief Executive Officer or Chief Financial Officer, or who is among the three most highly compensated executive officers for any fiscal year. The only exception to this rule is for compensation that is paid pursuant to a binding contract in effect on November 2, 2017 that would have otherwise been deductible under the prior Section 162(m) rules. Accordingly, any compensation paid in the future pursuant to new compensation arrangements entered into after November 2, 2017, even if performance-based, will count towards the $1.0 million
fiscal year deduction limit if paid to a covered executive. Additional information that may affect the Company's income tax accounts and disclosures would include further clarification and guidance on how the Internal Revenue Service will implement tax reform, including guidance with respect to 100% bonus depreciation on self-constructed assets and Section 162(m), further clarification and guidance on how state taxing authorities will implement tax reform and the related effect on our state income tax returns, completion of the Company's 2017 tax return filings, and the potential for additional guidance from the SEC or the FASB related to tax reform.
In assessing the ability to realize the benefit of the
DTA, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of DTL, 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. In regard to the Company's DTAs, the Company considered all available evidence in assessing the need for a valuation allowance.
At December 31,
2017 and 2016, the Consolidated Balance Sheet reflected a net deferred tax asset and liability of zero.
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits. The Company did
not have any additions, reductions or settlements of unrecognized tax benefits. In 2017, the Company generated no uncertain tax positions.
The Company's policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company's income tax provision. As of December 31, 2017, the Company did not have any accrued interest or penalties associated with any unrecognized
tax benefits, nor was any interest expense recognized during the current year.
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states. With few exceptions, the Company is subject to U.S. federal tax examination for years 2014 through 2017 and is subject to state tax examination for years 2013 through 2017.
10.
Stockholders' Equity
Common and Preferred Stock. The Company's authorized capital structure consists of 75,000,000 shares of preferred stock, par value $0.001 per share, and 300,000,000 shares of common stock, par value $0.001 per share. At the annual meeting in May 2017, a proposal to increase the number of authorized shares of common stock from 150,000,000 to 300,000,000 was approved. There are no issued and outstanding shares of preferred stock.
In
June 2015, the Company entered into an Equity Distribution Agreement (the "Agreement") with Goldman, Sachs and Co. (the "Manager"). Pursuant to the terms of the Agreement, the Company may sell, from time to time through or to the Manager, shares of its common stock having an aggregate gross sales price of up to $100.0 million. Sales of the shares, if any, will be made by means of ordinary brokers' transactions through the facilities of the New York Stock Exchange, at market prices, in block transactions, to or through a market maker, through an electronic communications network or as otherwise agreed by the Company and the Manager. As of December 31,
2017, and the date of this filing, no shares have been sold pursuant to the Agreement.
In June 2016, the Company issued 10,000,000 shares of common stock pursuant to the 2016 Debt Exchange with a holder of the Company's 7.625% Senior Notes. The holder exchanged $84.7 million principal amount of the 7.625% Senior Notes for 10,000,000 newly issued shares of the
Company's common stock.
In December 2016, the Company completed a public offering of its common stock, selling 15,525,000 shares at a price of $7.40 per share, par value $0.001 per share. The sale included the full exercise by the underwriters of their option to purchase 2,025,000 shares of common stock. Net proceeds from the sale of common stock, after deducting fees and expenses, were $109.7 million.
89
In
December 2017, the Company completed a public offering of its common stock, selling 23,205,529 shares at a price of $5.00 per share, par value $0.001 per share. The sale included the partial exercise of 2,205,529 shares of common stock by the underwriters from their option to purchase 3,150,000 shares of common stock. Net proceeds from the sale, after deducting fees and estimated expenses, were approximately $110.8 million.
In December 2017, the
Company issued 10,863,000 shares of common stock pursuant to the 2017 Debt Exchange with a holder of the Company's 7.0% Senior Notes. The holder exchanged $50.0 million principal amount of the 7.0% Senior Notes for 10,863,000 newly issued shares of the Company's common stock.
Treasury Stock. The Company may occasionally acquire treasury stock, which is recorded at cost,
in connection with the vesting and exercise of stock-based awards or for other reasons. As of December 31, 2017, all treasury stock held by the Company was retired.
The following table reflects the activity in the Company's common and treasury stock for the periods indicated:
Shares issued for nonvested shares of common stock
801,579
686,500
673,087
Shares
issued for debt exchange
10,863,000
10,000,000
—
Shares issued for equity offering
23,205,529
15,525,000
—
Shares
retired or forfeited
(296,415
)
(451,951
)
(411,803
)
Shares at end of period
110,363,539
75,721,360
49,864,512
Treasury
Stock:
Shares at beginning of period
—
—
—
Treasury
stock acquired
243,389
227,561
109,473
Treasury stock retired
(243,389
)
(227,561
)
(109,473
)
Shares
at end of period
—
—
—
11. Equity Incentive Compensation Plans and Other Long-term Incentive Programs
The
Company maintains various stock-based compensation plans and other employee benefit plans as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period). Cash-based compensation is measured at fair value at each reporting date and is recognized on a straight-line basis over the requisite service period (usually the vesting period).
The following table presents the long-term cash and equity incentive compensation related to awards for the periods indicated:
Unrecognized
compensation cost as of December 31, 2017 was $5.2 million related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.7 years.
(2)
The nonvested performance-based cash units are liability awards with $4.4 million, $2.9 million and $0.4 million included in derivatives and other noncurrent liabilities in the Consolidated Balance Sheets as of December 31,
2017, 2016 and 2015, respectively.
Stock Options and Nonvested Equity Awards. In May 2012, the Company's stockholders approved and the Company adopted its 2012 Equity Incentive Plan (the "2012 Incentive Plan"). The purpose of the 2012 Incentive Plan is to enhance the Company's ability to attract and retain officers, employees and directors and to provide such persons with an interest in the
Company aligned with the interests of stockholders. The 2012 Incentive Plan provides for the grant of stock options (including incentive stock options and non-qualified stock options) and other awards, including performance units, performance shares, share awards, share units, restricted stock, cash incentive, and stock appreciation rights or SARs.
The aggregate number of shares that the Company may issue under the 2012 Incentive Plan may not exceed 2,051,402 shares, subject to adjustment for future stock splits, stock dividends and similar changes in the Company's capitalization. Shares underlying grants that expire without being exercised or are forfeited
are available for grant under the 2012 Incentive Plan. The aggregate number of shares of common stock subject to options, stock appreciation rights, or performance-based awards granted to a participant during any calendar year may not exceed 500,000 shares. The 2012 Incentive Plan provides that all awards granted under the 2012 Incentive Plan expire not more than 10 years from the grant date and have an exercise price of no less than the closing price of the Company's common stock on the date of grant.
Currently, the Company's practice is to issue new shares upon stock option exercise. The
Company does not expect to repurchase any shares in the open market or issue treasury shares to settle any such exercises. For the years ended December 31, 2017, 2016 and 2015, the Company did not pay cash to repurchase any stock option exercises.
A summary of share-based option activity under all the Company's plans as of December 31, 2017, and changes during the year then ended, is presented below:
The
Company has not granted any share-based option awards since 2012.
(2)
At December 31, 2017, all share-based options granted have vested and are exercisable.
There have been no stock options exercised for the years ended December 31, 2017, 2016 and 2015.
The
Company grants service-based nonvested shares of common stock to employees and nonvested common stock units to non-employee or outside directors, which generally vest ratably over a three year service period for employees and over a one
year service period for directors. These awards are measured at fair value based on the closing price of the Company's common stock on the date of grant. A summary of the Company's nonvested shares of common stock as of December 31,
2017, 2016 and 2015, and changes during the years then ended, is presented below:
The
Company's outside directors receive annual compensation in the form of equity as common stock units, which are settled in common stock on a one-to-one basis. The outside directors may also elect to receive all or a portion of their quarterly cash compensation in the form of common stock units. Common stock units have only been granted to directors. A summary of the Company's nonvested common stock units as of December 31, 2017, 2016 and 2015, and changes during the years then ended, is presented in the table below:
The
fair value of equity awards vested for the years ended December 31, 2017, 2016 and 2015 was $3.1 million, $2.4 million and $3.4 million, respectively.
Performance Cash and Share Programs
For the years ended December 31, 2017, 2016 and 2015, the
Company granted performance-based cash units that will settle in cash. These awards are accounted for as liability awards and are measured at fair value at each reporting date using a Monte Carlo simulation. A summary of the Company's nonvested performance-based cash units as of December 31, 2017, 2016 and 2015, and changes during the years then ended, is presented below:
For the year ended December 31, 2014 and prior, the Company granted performance-based shares that settled in common stock. These awards are accounted for as equity awards. The market-based goals or total shareholder return ("TSR") goals associated with these awards are valued at each reporting date using a Monte Carlo simulation. The non-market-based goals are measured at fair value based on the closing price of the Company's common stock on the date of grant. A summary of the Company's vested performance-based shares of common
stock as of December 31, 2017, 2016 and 2015, and changes during the years then ended, is presented below:
The
Company has not granted any performance-based common stock awards since 2014.
(2)
The 2014 Program vested at 106.7% in excess of target level and resulted in additional shares vested in May 2017. These shares are included in the vested line item for the year ended December 31, 2017.
(3)
The Compensation Committee approved a special retention award on July 18, 2013. A debt
performance gate was required to be met as of December 31, 2013 in which the shares would vest on July 18, 2014, 2015 and 2016. The vested shares of 15,495 and 11,623 are included in the vested line item for the years ended December 31, 2016 and 2015, respectively.
The fair value of the performance-based shares vested in the years ended December 31, 2017, 2016
and 2015 was $0.6 million, $1.2 million and $0.1 million, respectively.
2017 Program. In February 2017, the Compensation Committee of the Board of Directors of the Company approved a performance cash program (the "2017 Program") granting performance cash units that will settle in cash and are accounted for as liability awards. The performance-based awards contingently vest in February 2020, depending on the level at which the performance goal is achieved. The performance goal, which will be measured over the three year period ending December
31, 2019, will be the Company's total shareholder return ("TSR") based on a matrix measurement of (1) the Company's absolute performance and (2) the Company's ranking relative to a defined peer group's individual TSRs ("Relative TSR"). The Company's absolute performance is measured against the December 30, 2016 closing share price of $6.99. If the Company's absolute performance is lower than the $6.99
share price, the payout is zero for this portion. If the Company's absolute performance is greater than the $6.99 share price, the performance cash units will vest 1% for each 1% in growth, up to 100% of the original grant. If the Company's Relative TSR is less than the median, the payout is zero for this portion. If the Company's Relative TSR is above the median, the payout is equal to twice the
Company's percentile rank above the median, up to 100% of the original grant. The Company's combined absolute performance and Relative TSR have a maximum vest of up to 200% of the original grant. A total of 669,043 units were granted under this program during the year ended December 31, 2017.
2016 Program. In March 2016, the Compensation Committee approved a performance cash program (the "2016 Program") granting performance cash units that will settle in cash and are accounted for as liability awards. The performance-based awards contingently vest in February 2019, depending
on the level at which the performance goal is achieved. The performance goal, which will be measured over the three year period ending December 31, 2018, will be the Company's TSR based on a matrix measurement of the Company's absolute performance and Relative TSR. The Company's absolute performance is measured against the December 31, 2015 closing share price of $3.93 and if the Company's absolute performance is lower than the $3.93 share
price, the payout is zero. If the Company's absolute performance is greater than the $3.93 share price, then the performance cash units will vest depending on the compound annual growth rate of the Company's absolute performance and the Relative TSR up to 200% of the original grant. A total of 646,572 units were granted under this program in during the year ended December 31, 2016.
2015 Program. In February 2015, the Compensation Committee approved a performance cash program (the "2015 Program") granting performance cash units that will settle in cash and are accounted for as liability awards. The performance-based awards contingently vest in May 2018, depending on the level at which the performance goals are achieved. The performance goals, which will be measured over the three year period ending December 31, 2017, consist of the TSR compared to Relative TSR (weighted at 60%) and the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group's percentage calculation ("DCF per Debt Adjusted Share") (weighted at 40%). The Relative TSR and DCF per
Debt Adjusted Share goals will vest at 25% or 50%, respectively, of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric are between the threshold and target levels or between the target and stretch levels, the vested number of units will be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics are not met, no units will vest. In any event, the total number of units that could vest will not exceed 200% of the original number of performance cash units granted. At the end of the three year vesting period, any units that have not vested will be forfeited. A total of 422,345
units were granted under this program during the year ended December 31, 2015. All compensation expense related to the TSR metric will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. All compensation expense related to the DCF per Debt Adjusted Share metric will be based on the number of shares expected to vest at the end of the three year period. Based upon the Company's performance through 2017, approximately 104.1% of the 2015 Program performance units are expected to vest in May 2018.
2014 Program. In February 2014, the Compensation Committee approved a performance share program (the "2014
Program") pursuant to the 2012 Equity Incentive Plan. The awards in this program settled in shares of common stock. The performance-based awards vested in May 2017, based on the level at which the performance goals were achieved. The performance goals, which were measured over the three year period ending December 31, 2016, consisted of the TSR compared to Relative TSR (weighted at 60%) and the percentage change in DCF per Debt Adjusted Share (weighted at 40%). The Relative TSR and DCF per Debt Adjusted Share goals were to vest at 25% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric were
between the threshold and target levels or between the target and stretch levels, the vested number of shares would be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics were not met, no shares would vest. In any event, the total number of shares of common stock that could vest would not exceed 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that did not vest were forfeited. A total of 315,661 shares were granted under this program during the year ended December 31, 2014. All compensation expense related to the TSR metric was recognized if the requisite service period was fulfilled, even if the market condition was not achieved. All compensation expense related to the DCF per Debt Adjusted Share metric
was based on the number of shares expected to vest at the end of the three year period. Based upon the Company's performance through 2016, 106.7% or 166,023 shares of the 2014 Program vested in May 2017.
2013 Program. In February 2013, the Compensation Committee approved a new performance share program (the "2013 Program") pursuant to the 2012 Equity Incentive Plan. The performance-based awards vested in May 2016, based on the level at which the performance goals were achieved. The performance goals were measured over the three year period ending December 31, 2015, and consisted of the Relative TSR (weighted at 33
1/3%), the percentage change in DCF per Debt Adjusted Share (weighted at 33 1/3%) and percentage change in proved oil, natural gas and NGL reserves per debt adjusted share ("Reserves per Debt Adjusted Share") (weighted at 33 1/3%). The Relative TSR and DCF per Debt Adjusted Share goals were to vest at 25% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. The Reserves per Debt Adjusted Share goal were to vest at 50% of the total award for performance met at the threshold level, 100% at the target level and 200%
at the stretch level. If the threshold metrics were not met, no shares would vest. The total number of vested shares of common stock would not exceed 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that were not vested would be forfeited. All compensation expense related to the Relative TSR metric was recognized to the extent the requisite service period was fulfilled, even if the market condition was not achieved. All compensation expense related to the DCF per Debt Adjusted Share metric and the Reserves per Debt Adjusted Share metric was based upon the number of shares expected to vest at the end of the three year period. A total of 450,544 shares were granted under this program during the year ended December 31, 2013. Based upon the
Company's performance through 2015, 59.6% or 141,080 shares of the 2013 Program vested in May 2016.
Other Employee Benefits-401(k) Savings Plan. The Company has an employee-directed 401(k) savings plan (the "401(k) Plan") for all eligible employees over the age of 21. Under the 401(k) Plan, employees may make voluntary contributions based on a percentage of their pretax income, subject to statutory limitations.
The Company matches 100%
of each employee's contribution, up to 6% of the employee's pretax income. Starting on April 1, 2015, the entire 6% match is comprised solely of cash; the match in previous periods consisted of 50% cash and 50% common stock. The Company's cash and common stock contributions are fully vested upon the date of match, and employees
can immediately
sell the portion of the match made with the Company's common stock. The Company made matching cash contributions of $1.0 million for both of the years ended December 31, 2017 and 2016, respectively, and cash and common stock contributions of $1.2 million for the year ended December 31, 2015.
Deferred Compensation Plan. In 2010, the
Company adopted a non-qualified deferred compensation plan for certain employees and officers whose eligibility to participate in the plan was determined by the Compensation Committee. The Company makes matching cash contributions on behalf of eligible employees up to 6% of the employee's cash compensation once the contribution limits are reached on the Company's 401(k) Plan. All amounts deferred and matched under the plan vest immediately. Deferred compensation, including accumulated earnings on the participant-directed investment selections, is distributable in cash at participant-specified dates or upon retirement, death, disability, change in control or termination of employment.
The
Company has established a rabbi trust to offset the deferred compensation liability and protect the interests of the plan participants. The investments in the rabbi trust seek to offset the change in the value of the related liability. As a result, there is no expected impact on earnings or earnings per share from the changes in market value of the investment assets because the changes in market value of the trust assets are offset by changes in the value of the deferred compensation plan liability. The gains and losses from changes in fair value of the investments are included in interest and other income in the Consolidated Statements of Operations.
The following table represents the Company's activity in the investment assets held in the rabbi trust during the years ended December 31,
2017 and 2016:
12.
Significant Customers and Other Concentrations
Significant Customers. 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. Collectability is dependent upon the financial stability of each individual company and is influenced
by the general economic conditions of the industry. The Company normally sells production to a relatively small number of customers, as is customary in the development and production business. The
Company sells natural gas and related NGLs to two primary gas gathering and processing companies. Based on where the Company operates and the availability of other purchasers and markets, the Company believes that its production could be sold in the market in the event that it is not sold to its existing customers. However, in some circumstances, a change in customers may entail significant costs during the transition to a new customer.
Concentrations of Market Risk. The future results of the Company's oil and gas operations will be affected by the market prices of oil, natural gas and NGLs.
A readily available market for oil, natural gas and NGLs in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and NGLs, the regulatory environment, the economic environment and other regional, national and international economic and political events, none of which can be predicted with certainty.
The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from purchasers of oil and gas production and amounts due from
joint venture partners for their respective portions of operating expenses and exploration and development costs. The Company believes that no single customer or joint venture partner exposes the Company to significant credit risk. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the natural gas or oil industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company's results of operations in the long-term. Trade receivables are
generally not collateralized. The Company analyzes customers' and joint venture partners' historical credit positions and payment histories prior to extending credit.
Concentrations of Credit Risk. Derivative financial instruments that hedge the price of oil, natural gas and NGLs are generally executed with major financial or commodities trading institutions which expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company's policy is to execute financial derivatives only with major, creditworthy financial
institutions. The Company has derivative instruments with seven different counterparties, of which all are lenders or affiliates of lenders in the Amended Credit Facility.
The creditworthiness of counterparties is subject to continuing review, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties. Where the counterparty is a lender under the Amended Credit Facility, the counterparty risk is mitigated to the extent that the
Company is indebted to such lender under the Amended Credit Facility.
13. Commitments and Contingencies
Lease Financing Obligation. The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note 5. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below. The Lease Financing Obligation contains an early buyout option pursuant to which the
Company may purchase the equipment for $1.8 million on February 10, 2019.
Transportation
Charges. The Company is party to two firm transportation contracts, through July 2021, to provide capacity on natural gas pipeline systems. The contracts require the Company to pay transportation charges regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are included in unused commitments expense in the Consolidated Statements of Operations. As a result of previous divestitures in 2013 and 2014, the
Company will likely not utilize the firm capacity on the natural gas pipelines.
The amounts in the table below represent the Company's future minimum transportation charges.
Lease
and Other Commitments. The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. The Company incurred rent expense related to these operating leases of $1.9 million, $2.0 million and $2.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. Additionally, the Company has entered into various long-term agreements
for telecommunication services. Future minimum annual payments under lease and other agreements are as follows:
Litigation.
The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the course of ordinary business. It is the opinion of the Company's management that current claims and litigation involving the Company are not likely to have a material adverse effect on its consolidated balance sheets, cash flows or statements of operations.
In
addition to the Amended Credit Facility, the 7.0% Senior Notes and the 8.75% Senior Notes, have been registered under the Securities Act of 1933, are jointly and severally guaranteed on a full and unconditional basis by the Company's 100% owned subsidiaries ("Guarantor Subsidiaries"). Presented below are the Company's condensed consolidating balance sheets, statements of operations, statements of other comprehensive income (loss) and statements of cash flows, as required by
Securities and Exchange Commission Rule 3-10 of Regulation S-X.
On December 29, 2017, the Company completed the sale of its remaining non-core assets in the Uinta Basin, which included Aurora Gathering, LLC, a 100% owned subsidiary of the Company.
During the year ended December 31, 2015, Bill Barrett Corporation, as parent, merged a 100% owned subsidiary, Elk Production Uintah, LLC, into the parent company. The condensed consolidating financial statements reflect the new guarantor structure for all periods presented.
The following condensed consolidating financial statements have been prepared from the Company's financial information on the same basis of accounting as the Consolidated Financial Statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Company and the Guarantor Subsidiaries are reflected in the intercompany eliminations column.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(In Thousands, Except Per Share Data Unless Otherwise Indicated)
(Unaudited)
Oil and Gas Producing Activities
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion per equivalent unit-of-production were as follows:
Supplemental Oil and Gas Reserve Information. The reserve information presented
below is based on estimates of net proved reserves as of December 31, 2017, 2016 and 2015 that were prepared by internal petroleum engineers in accordance with guidelines established by the SEC and were audited by the Company's independent petroleum engineering firm NSAI in 2017, 2016 and 2015.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable
in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Analysis of Changes in Proved Reserves. The following table sets forth information regarding the Company's estimated net total proved and proved developed oil and gas reserve quantities:
At
December 31, 2017, the Company's proved reserves increased by 8.8 MMBoe due to positive revisions of previous estimates and by 35.9 MMBoe through extensions, discoveries and other additions. These increases to proved reserves were the result of the 2017 drilling activity and the timing of development with 2 drilling rigs. The increase in proved reserves was offset by the sale of the Company's non-core assets in the Uinta Basin.
At December 31, 2016, the Company revised its proved
reserves downward by 30.4 MMBoe primarily as a result of classifying 24.3 MMBoe of proved undeveloped reserves as probable reserves due to the timing of development within the five year window as defined by the SEC. In addition, the Company had engineering revisions of 5.8 MMBoe due to performance from existing proved developed wells.
At December 31, 2015, the Company revised its proved reserves downward by 24.4 MMBoe primarily as a result of negative price revisions of 25.0 MMBoe, as 2015 pricing was $2.59 per MMBtu and $50.28 per barrel of oil compared with pricing for 2014 of $4.35 per MMBtu and $94.99 per barrel of oil. Prices were adjusted by lease for
quality, transportation fees and regional price differences.
Standardized Measure. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is important for a proper understanding and assessment of the data presented.
For the years ended December 31,
2017, 2016 and 2015, future cash inflows are calculated by applying the 12-month average pricing (as is required by the rules of the Securities and Exchange Commission) of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves. For the year ended December 31, 2017, calculations were made using adjusted average prices of $48.87 per Bbl for oil, $17.21 per Bbl for NGLs and $2.29 per MMBtu for gas, as compared to the average benchmark prices of $51.34 per Bbl for oil, $27.40 per Bbl for NGLs and $2.98
per Mcf for gas. For the year ended December 31, 2016, calculations were made using adjusted average prices of $36.52 per Bbl for oil, $9.18 per Bbl for NGLs and $2.08 per MMBtu for gas, as compared to the average benchmark prices of $42.75 per Bbl for oil, $19.70 per Bbl for NGLs and $2.48 per Mcf for gas. For the year ended December 31, 2015, calculations were made using adjusted average prices of $40.03 per Bbl for oil, $10.47 per Bbl for NGLs and $2.11 per MMBtu for gas, as compared to the average benchmark prices of $50.28 per Bbl for oil, $20.37 per Bbl for NGLs and $2.59
per Mcf for gas. The differences between the average benchmark prices and the adjusted average prices used in the calculation of the standardized measure are attributable to adjustments made for transportation, quality and basis differentials. The Company also records an overhead charge against its future cash flows.
The assumptions used to calculate estimated future cash inflows do not necessarily reflect the Company's expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's
control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Future development and production costs are calculated by estimating the expenditures to be incurred in developing and producing the proved oil, gas and NGL reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash
flows relating to the Company's proved oil, gas and NGL reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.
The following table presents the standardized measure of discounted future net cash flows related to proved oil, gas and NGL reserves:
Standardized measure of discounted future net cash flows
$
829,311
$
329,309
$
327,566
The
"standardized measure" is the present value of estimated future cash inflows from proved oil, 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.
The present value (at a 10% annual discount) of future net cash flows from the Company's proved reserves is not necessarily the same as the current market value of its estimated oil, gas and NGL reserves. The
Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs in effect on the day of estimate in accordance with the applicable accounting guidance. However, actual future net cash flows from its oil, gas and NGL properties will also be affected by factors such as actual prices the Company receives for oil, gas and NGL, the amount and timing of actual production, supply of and demand for oil and natural gas and changes in governmental regulations or taxation.
The timing
of both the Company's production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.
A summary of changes in the standardized measure of discounted future net
cash flows is as follows:
Standardized measure of discounted future net cash flows, beginning of period
$
329,309
$
327,566
$
1,169,582
Sales
of oil and gas, net of production costs and taxes
(191,669
)
(119,167
)
(127,015
)
Extensions, discoveries and improved recovery, less related costs
346,973
58,121
33,085
Quantity
revisions
112,452
(228,538
)
(202,035
)
Price revisions
253,738
(157,414
)
(1,647,642
)
Previously
estimated development costs incurred during the period
138,094
52,611
154,985
Changes in estimated future development costs
(118,967
)
377,239
606,736
Accretion
of discount
31,816
31,941
145,387
Purchases of reserves in place
42,979
—
—
Sales
of reserves
(107,620
)
(10,736
)
(82,081
)
Changes in production rates (timing) and other
(7,794
)
(2,314
)
(2,747
)
Net
changes in future income taxes
—
—
279,311
Standardized measure of discounted future net cash flows, end of period
$
829,311
$
329,309
$
327,566
Quarterly
Financial Data
The following is a summary of the unaudited quarterly financial data, including income (loss) before income taxes, net income (loss) and net income (loss) per common share for the years ended December 31, 2017 and 2016.
