Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34 Filing Table of Contents
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Employee Benefits (Tables)
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Additional Information (Detail)
36: R37 Summary of Significant Accounting Policies - HTML 42K
Summary of Accounts Receivable (Detail)
102: R38 Summary of Significant Accounting Policies - Net HTML 62K
Capitalized Costs and Associated Accumulated
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Changes in Capitalized Exploratory Well Costs
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54: R40 Summary of Significant Accounting Policies - HTML 56K
Non-Cash Impairment Charges, Included within
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93: R41 Summary of Significant Accounting Policies - HTML 42K
Accounts Payable and Accrued Liabilities (Detail)
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Calculation of Basic and Diluted Earnings (Loss)
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- Supplemental Cash Flow Information (Detail)
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58: R45 Divestitures - Asset Held for Sale (Details) HTML 47K
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Interest Expense Related to Long Term Debt
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Retirement Obligations (Detail)
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Derivative Instruments (Detail)
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Losses (Detail)
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Hedging Volume (Detail)
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Gains and Losses on Commodity Derivative
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Employee Benefits - Fair Value Assumptions and
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Employee Benefits - Summary of Share-Based Option
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Employee Benefits - Summary of Nonvested Equity
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Shares of Common Stock Issued for Payment of
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Additional Information (Detail)
28: R76 Commitments and Contingencies - Additional HTML 45K
Information (Detail)
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Aggregate Undiscounted Minimum Future Lease
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Minimum Transportation Demand and Firm Processing
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Annual Payments under Drilling, Lease and Other
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Consolidating Balance Sheets (Detail)
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Consolidating Statements of Operations (Detail)
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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
Series A Junior Participating Preferred Stock Purchase Rights
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
þ Yes ¨ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
¨ Yes þ No
Indicate by check mark whether the
registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted
and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate
by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,”“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
þ
Accelerated filer
¨
Non-accelerated
filer
¨ (Do not check if a smaller reporting company)
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
¨ Yes þ No
The
aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 28, 2013 based on the $20.22 closing price of the registrant's common stock on the New York Stock Exchange was $978,357,338.
__________
*
Calculated based on beneficial ownership of our common stock on January 24, 2014. Without assuming that any of the
registrant’s directors, executive officers, or 10 percent or greater beneficial owners is an affiliate, the shares of which they are beneficial owners have been deemed to be owned by affiliates solely for this calculation.
The information required in
Part III of this Annual Report on Form 10-K is incorporated by reference from the registrant’s definitive proxy statement for the registrant’s Annual Meeting of Stockholders to be held in May 2014 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant’s fiscal year ended December 31, 2013.
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and gas industry:
2-D seismic. The standard acquisition technique used to image geologic formations over a broad area. Data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. 2-D seismic data produces an image of a single vertical plane of sub-surface data.
3C 3-D seismic. A three dimensional seismic survey employing three-component geophones. These multi-component geophones record three orthogonal components of ground motion and provide
information about shear waves that are unobtainable by conventional 3-D seismic surveys.
3-D seismic. Acoustical reflection data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
Basin-centered gas. A regional, abnormally pressured, gas-saturated accumulation in low-permeability reservoirs lacking a down-dip water contact.
Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume.
Bcf. Billion cubic feet of natural gas.
Boe.
Barrel of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.
Boe/d. Boe per day.
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Coalbed methane or CBM. Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and can be produced into a pipeline.
Completion. Installation of permanent equipment for production of oil and gas, or, in the case of a dry well, to reporting
to the appropriate authority that the well has been abandoned.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Curtailments. The delivery of gas below contract entitlements due to system restrictions.
Delineation. The process of drilling wells away from, or that is removed from, a known point of well control.
Developed acreage. The number of acres that are allocated or assignable to productive
wells or wells capable of production.
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Down-dip. The occurrence of a formation at a lower elevation than a nearby area.
Drill-to-earn. The process of earning an interest in leasehold acreage by drilling a well pursuant to a farm-in, exploration, or other agreement.
Dry hole or Dry well. An exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Environmental Assessment or EA. A study that can be required prior to drilling a federal well.
Environmental Impact Statement or EIS. A more detailed study of the potential direct, indirect and cumulative impacts of a federal project that may be made available for public review and comment.
Exploratory well. A well drilled to find
a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Henry Hub. The Erath, LA settlement point price as quoted in Platt’s Gas Daily on the first flow day of each month.
Horizontal drilling. A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill
bit to drill horizontally within a designated zone typically defined as the prospective pay zone to be completed for oil and or gas.
Hydraulic fracturing. The injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas and oil production.
Identified drilling locations. Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.
MBbls.
Thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. Thousand barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.
Mcf. Thousand cubic feet of natural gas.
MMBbls. Million barrels of crude oil or other liquid hydrocarbons.
MMBoe. Million barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.
MMBtu. Million British thermal units.
MMcf.
Million cubic feet of natural gas.
Mt. Belvieu. The average daily price as quoted by Oil Price Information Service for Mont Belvieu spot gas liquid prices.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.
Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
NGLs. Natural gas liquids.
NWPL. Northwest Pipeline Corporation price as quoted in Platt’s Inside FERC on the first business day of each month.
Play.
A term used to describe an accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Potentiometric surface. An imaginary surface defined by the level to which
water in an aquifer would rise due to the natural pressure in the rocks.
Productive well. An exploratory, development, or extension well that is not a dry well.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves or PDP. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The quantities of oil, natural
gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.
Proved undeveloped reserves or PUD. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Resource Management Plan or RMP. A
document that describes the U.S. Bureau of Land Management’s intended uses of lands that are under its jurisdiction.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
SEC. U.S. Securities and Exchange Commission.
Shale gas. Considered to be an unconventional accumulation of natural gas where the gas is recovered from extremely low permeability shales, generally through the use of horizontal drilling and hydraulic fracturing.
Standardized Measure. The present value of estimated future cash
inflows from proved oil, natural gas and NGL reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner the right to drill,
produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
WTI. West Texas Intermediate price as quoted on the New York Mercantile Exchange.
WTI Cushing. The West Texas Intermediate price at the Cushing, OK settlement point as quoted by Bloomberg, using crude oil price bulletins for the first day of each month.
This
Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements about our future strategy, plans, estimates, beliefs, timing and expected performance.
All of these types of statements, other than statements of historical fact included in or incorporated into this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in “Items 1 and 2. Business and Properties”, “Item 1A. Risk Factors”, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other sections of this Annual
Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as “expect”, “seek”, “believe”, “upside”, “will”, “may”, “expect”, “anticipate”, “plan”, “will be dependent on”, “project”, “potential”, “intend”, “could”, “should”, “estimate”, “predict”, “pursue”, “target”, “objective”, or “continue”, the negative of such terms or other comparable terminology.
Forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the following risks and uncertainties:
•
volatility
of market prices received for oil, natural gas and NGLs;
•
actual production;
•
changes in the estimates of proved reserves;
•
reductions in the borrowing base under our revolving bank credit facility (the “Amended Credit Facility”);
•
legislative
or regulatory changes that can affect our ability to receive drilling and other permits and surface rights, including initiatives related to drilling and completion techniques including hydraulic fracturing;
•
availability of third party goods and services at reasonable rates;
•
liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered
by an effective indemnity or insurance; and
•
other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Item 1A. Risk Factors” all of which are difficult to predict.
In light of these and other risks, uncertainties and assumptions, forward-looking events may not occur.
The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions
reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to many factors including those listed above and in “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Readers should
not place undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not intend to, and do not undertake any obligation to, publicly update or revise any forward-looking statements as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
Bill Barrett Corporation together with our wholly-owned subsidiaries (“the Company”, “we”, “our” or “us”) is an independent energy company that develops, acquires and explores for oil and natural gas resources. All of our assets and operations are located in the Rocky Mountain region of the United States.
We seek to build stockholder value by delivering profitable
growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize our operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices and from the settlement of commodity hedges. Due to current and expected commodity prices for oil, natural gas and NGLs, we are focused on developing oil assets where we have established a long-term inventory of drilling locations. As a result, we have transitioned our portfolio to have a better balance in the mix of oil, natural gas, and NGLs for both production and reserves.
We are committed to developing and producing
oil and natural gas in a responsible and safe manner. Our employees work diligently with environmental, wildlife and community organizations to ensure that exploration and development activities are designed with all stakeholders in mind.
We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed an initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. Our common stock is traded on the New York Stock Exchange under the symbol “BBG”. The principal executive offices are located at 1099 18th Street, Suite 2300, Denver, Colorado80202, and the telephone
number at that address is (303) 293-9100.
We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC via EDGAR and posted at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines and the charters of our Audit Committee, Compensation Committee, Reserves and EHS Committee and Nominating and Corporate Governance Committee are posted
on our website at http://www.billbarrettcorp.com and are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 1099 18th Street, Suite 2300, Denver, 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.
The following table provides summary information by basin as of December 31, 2013:
Our
proved reserves were determined in accordance with SEC guidelines, using the average price on the first of each month for natural gas (Henry Hub price) and oil (WTI Cushing price), which averaged $3.67 per MMBtu of natural gas and $96.91 per barrel of oil in 2013, respectively, without giving effect to hedging transactions. The average NGL price of $39.75 per barrel was based on a percentage of the SEC oil price per barrel based on historical price data. Our reserves estimates are based on a reserve report prepared by us and audited by our independent third party petroleum engineers. See “– Oil and Gas Data – Proved Reserves”.
(2)
Excludes average
daily net production for our West Tavaputs area in the Uinta Basin, which was sold in December 2013.
(3)
Net wells are the sum of our fractional working interests owned in gross wells.
(4)
Includes 36,281 net undeveloped acres associated with our Cottonwood Gulch prospect.
(5)
Excludes an additional
67,500 net undeveloped acres that are subject to drill-to-earn agreements.
Areas of Operation
Overview
Through our operations, we have transitioned our portfolio to have a better balance in the mix of oil, natural gas and NGLs for both production and reserves. As of December 31, 2013, we had three key areas of production: The Denver-Julesburg Basin (“DJ Basin”), the Uinta Oil Program in the Uinta Basin, and the Gibson Gulch area in the Piceance Basin. We also operate an early stage oil program in Powder River
Basin and hold acreage in a number of exploration areas. Among these assets, we actively invested in the DJ Basin, the Uinta Oil Program and the Powder River Oil Program during 2013, all of which target oil resources.
The following table represents the percentage change in the mix of oil, natural gas and NGLs for both production and reserves:
Oil
production and proved reserves for 2013 include NGLs.
(2)
For periods prior to January 1, 2013, we presented our production and reserve data for oil and natural gas, which combined NGLs with the natural gas stream, and did not separately report NGLs. This change impacts the comparability of 2013 with prior periods.
Denver-Julesburg Basin
The Company’s
acreage positions in the DJ Basin are predominantly located in Colorado’s eastern plains and parts of southeastern Wyoming.
Producing wells - We had interests in 324 gross (203.3 net) producing wells as of December 31,
2013, and we serve as operator in 209 gross wells.
•
2013 net production - 1,288 MBoe.
•
Acreage - We held 60,672 net undeveloped acres as of December 31, 2013.
•
Capital
expenditures - Our capital expenditures for 2013 were $209.3 million for participation in the drilling of 78 gross wells, acquire leasehold acres and to construct gathering facilities.
•
As of December 31, 2013, we were drilling 2 gross wells (0.9 net), and we were waiting to complete 16 gross (12.8 net) wells within the DJ Basin.
•
As of December
31, 2013, we had a 55% weighted average working interest in producing wells in the DJ Basin.
Our DJ Basin acreage was acquired predominantly through two acquisitions completed in August 2011 and July 2012. The DJ Basin is a high growth oil development area where operators are targeting the Niobrara and Codell formations, and employing new technologies to optimize oil recoveries and economic returns. We believe that the DJ Basin offers us significant growth opportunity through further delineating our current position, potential down-spacing, planned testing of extended reach horizontal wells and further cost optimizations.
The DJ Basin is a core area of operation where we drilled 61 operated wells and completed 44 operated wells in 2013 and had four rigs operating at the end of 2013. In 2013, we focused on delineating the majority of our position in the Northeast
Wattenberg area of the DJ Basin, optimizing our completion technology and establishing a scalable development program. In 2013, we drilled 51 operated wells in this area, which was largely undrilled, thereby delineating an estimated 70% of that net 40,000 acre position. In 2013, we also drilled 10 operated wells in the core Wattenberg portion of our position, which is largely de-risked as a result of existing production from vertical wells in the field.
The 2014 drilling program will be predominantly pad drilling, employ an average of three rigs for approximately 85 gross/60 net operated wells plus approximately 45 non-operated wells. The 2014 drilling program includes a combination of standard length and extended reach (9,000 foot) laterals, and downspacing to 40-acres. This program may be modified throughout 2014 as business conditions and operating results warrant.
Our
oil production is sold at the lease and trucked to markets. Our gas production is gathered and processed by various third parties and we receive residue gas and NGL revenue under percentage of proceeds contracts.
Uinta Basin
The Uinta Basin is located in northeastern Utah. During 2013, our development operations were conducted through two key programs: our Uinta Oil Program and the West Tavaputs area, which is primarily a natural gas development. The West Tavaputs assets were sold in December 2013 and, therefore, are not included in the key statistics below.
Producing wells - We had interests in 299 gross (170.2 net) producing wells as of December 31, 2013, and we serve as operator in 216 gross
wells.
•
2013 net production - 2,642 MBoe.
•
Acreage - We held 70,795 net undeveloped acres as of December 31, 2013, along with 67,500 net undeveloped acres that are subject to drill-to-earn agreements.
•
Capital
expenditures - In 2013, our capital expenditures were $204.4 million for participation in the drilling of 69 gross (33.5 net) wells, acquire leasehold acres and to construct gathering and salt water disposal facilities.
•
As of December 31, 2013, we were not in the process of drilling or completing any wells.
•
As of December 31, 2013,
we had a 61% weighted average working interest in producing wells in the Uinta Oil Program.
The Uinta Oil Program includes four areas of development that are located around the basin that we refer to as Blacktail Ridge, Lake Canyon, East Bluebell and South Altamont. The Uinta Oil Program has a sizable acreage position with a long-term drilling inventory, offering us significant growth potential. The resource is a stacked oil play with multiple pay zones, and our drilling program targets multiple zones from the Lower Green River through the Wasatch with vertical wells. The Uinta Oil Program is a core area of operation where we drilled and completed 57 operated wells during 2013.
During 2013, the Company conducted two 80-acre spacing
pilot projects, one each in the southern and northern portions of the Blacktail Ridge area. Results to date indicate minimal, if any, interference with appropriate well orientation.
In 2014, the Company will concentrate on development in the East Bluebell area and employ an average of two rigs for approximately 35 wells.
Our oil production is sold at the lease and trucked to markets. Our gas production is gathered and processed by various third parties and we receive residue gas and NGL revenue under percentage of proceeds contracts.
Piceance
Basin
The Piceance Basin is located in northwestern Colorado. We began operations in the Gibson Gulch area of the Piceance Basin in 2004, after we purchased producing and undeveloped properties.
Producing
wells - We had interests in 956 gross (745.0 net) producing wells as of December 31, 2013, and we serve as the operator in 926 gross wells.
•
2013 net production - 6,434 MBoe.
•
Acreage - We held 41,011 net undeveloped acres, including the Cottonwood Gulch prospect, as of December 31, 2013.
•
Capital expenditures - Our capital expenditures for 2013 were $3.9 million for various gas lift projects.
•
As of December 31, 2013, we were not in the process of drilling or completing any wells.
•
At
December 31, 2013, we had a 78% weighted average working interest in producing wells in the Piceance Basin.
The Gibson Gulch area is a basin-centered gas play along the north end of the Divide Creek anticline near the eastern limits of the Piceance Basin’s productive Mesaverde (Williams Fork) trend, and is at a depth of approximately 7,500 feet. Reserves in this area are based on 10-acre density. On December 31, 2012, we closed the sale of an 18% working interest in our Gibson Gulch properties; the working interest sold progresses to 21% for 2014, 24% for 2015 and 26% in 2016.
Our natural gas production in this basin is
currently gathered through our own gathering system and Summit Midstream Partner, LLC’s gathering system and delivered to markets through a variety of interstate pipelines. The energy content of our Piceance gas is approximately 1.15 BTU per cubic foot, and the natural gas is processed at an Enterprise Products Partners L.P. plant in Meeker, Colorado. We have the option annually to elect to process liquids with Enterprise Products Partners L.P. and
receive the value of NGLs with Mt. Belvieu pricing for a portion of our production. Our oil production is sold at the lease and trucked to markets.
As a result of the current outlook
for natural gas prices, we do not plan to drill in the Piceance Basin in 2014. This plan may change during the year as business conditions and operating results warrant.
Powder River Basin
The Powder River Basin is located in northeastern Wyoming. Our operations in the Powder River Basin target oil reservoirs.
Producing wells - We had interests in 105 gross (18.1 net) producing wells as of December 31, 2013, and we serve as operator in 17 gross wells.
•
2013 net production - 437 MBoe.
•
Acreage
- We held 57,806 net undeveloped acres as of December 31, 2013.
•
Capital expenditures - Our capital expenditures for 2013 were $52.3 million for participation in the drilling of 20 gross (4.8 net) wells and to acquire leasehold acres.
•
As of December 31, 2013, we were not in the process
of drilling or completing any wells.
•
At December 31, 2013, we had a 15% weighted average working interest in producing wells in the Powder River Basin.
Our Powder River Oil Program targets various Cretaceous oil bearing horizons including the Parkman, Sussex, Shannon, Niobrara, Turner and Frontier formations through horizontal wells. The Powder River Oil Program is an early stage program where we believe there is significant potential for growth in reserves and production from its acreage position. During 2013, we drilled and completed five operated wells and participated in 15 non-operated
wells.
In 2014, we plan to participate in approximately 34 gross non-operated wells.
Our oil production is sold at the lease and trucked to markets. Our gas production is gathered and processed by various third parties and we receive residue gas and NGL revenue under percentage of proceeds contracts.
Oil and Gas Data
Historically, we have presented separate reserve data for oil and natural gas. This is known as “two streams” reporting and is the
manner in which all the data prior to January 1, 2013 below is presented. Beginning January 1, 2013, we modified our gas processing agreements with various processors to take title to NGLs resulting from the processing of our natural gas. Therefore, we have reported reserve and production data separately for oil, natural gas and NGLs for periods after January 1, 2013 below. This is known as “three streams reporting”.
Proved Reserves
The following table presents our estimated net proved oil, natural gas and NGLs reserves and the present value of our estimated proved reserves
at each of December 31, 2013, 2012 and 2011 based on reserve reports prepared by us and audited by outside independent third party petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our estimates independently audited, we are required by our revolving credit agreement with our lenders to have an independent third party engineering firm perform an annual audit of our estimated reserves. All of our proved reserves included in our reserve reports are located in North America. Netherland, Sewell & Associates, Inc., or “NSAI”, audited all our reserves estimates at December 31, 2013, 2012
and 2011. NSAI is retained by and reports to the Reserves and EHS Committee of our Board of Directors, which is comprised of independent directors. When compared on a well-by-well or lease-by-lease basis, some of our internal estimates of net proved reserves are greater and some are less than the estimates of outside independent third party petroleum engineers. However, in the aggregate, the independent third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates. In addition to a third party audit, our reserves are reviewed by our Reserves and EHS Committee. The Reserves and EHS Committee reviews the final
reserves
estimates in conjunction with NSAI’s audit letter and meets with the key representative of NSAI to discuss NSAI’s review process and findings. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency, other than the SEC, since January 1, 2013.
As of December 31,
Proved
Reserves:
2013
2012
2011
Proved Developed Reserves:
Oil
(MMBbls)
26.3
20.7
10.4
Natural gas (Bcf)
238.7
492.1
632.5
NGLs
(MMBbls)
17.2
—
—
Total proved developed reserves (MMBoe) (1)
83.2
102.7
115.8
Proved
Undeveloped Reserves:
Oil (MMBbls)
57.2
30.1
20.2
Natural
gas (Bcf)
227.7
247.1
548.6
NGLs (MMBbls) (2)
18.6
—
—
Total
proved undeveloped reserves (MMBoe) (1)
113.7
71.2
111.6
Total Proved Reserves (MMBoe) (1)
197.0
174.0
227.4
(1)
Total
does not add because of rounding.
(2)
The increase in NGLs includes the impact of the Company's conversion to three stream production. Prior to 2013, NGL reserves were included in natural gas data, which impacts the comparability for the periods presented.
The data in the above table represent estimates only. Oil, natural gas and NGLs reserve engineering is an estimation of accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserves estimate is a function of the quality of available data and engineering
and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered. See “Item 1A. Risk Factors”.
Proved developed oil, natural gas and NGLs reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil, natural gas and NGLs reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those locations on development spacing areas that are offsetting economic producers that are reasonably certain of economic production when drilled. Proved undeveloped reserves for other undrilled development spacing areas can
be claimed only where it can be demonstrated with reasonable certainty that there is continuity of economic production from the existing productive formation. Proved undeveloped reserves are included when they are scheduled to be drilled within five years.
Proved undeveloped locations converted to proved developed wells during year
49
179
182
Proved
undeveloped drilling and completion capital invested (in millions)
$
118.8
$
362.2
$
209.9
Proved undeveloped facilities capital invested
(in millions)
$
6.8
$
45.6
$
20.0
Percentage of proved undeveloped reserves converted to proved developed
11.0
%
20.4
%
22.7
%
Prior
year’s proved undeveloped reserves remaining undeveloped at current year end (MMBoe)
42.7
54.0
70.3
At December 31, 2013, our proved undeveloped
reserves were 113.7 MMBoe. At December 31, 2012, our proved undeveloped reserves were 71.2 MMBoe. During 2013, 7.8 MMBoe, or 11.0% of our December 31, 2012 proved undeveloped reserves (49 wells), were converted into proved developed reserves and required $118.8 million of drilling and completion capital and $6.8 million of facilities capital. These wells produced 0.7 MMBoe in 2013. During 2013, we added 64.2 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. During 2013, 22.8 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans and were either traded, sold or
removed. This volume includes 10.5 MMBoe of proved undeveloped reserves sold in the divestiture of our West Tavaputs properties. Positive engineering and pricing revisions increased proved undeveloped reserves by 8.9 MMBoe. Significant pricing revisions occurred in many of our producing areas, particularly our Piceance Basin natural gas producing area, due to the pricing change from $2.56 per MMBtu CIG for the year ended December 31, 2012 to $3.67 per MMBtu Henry Hub for the year ended December 31, 2013 and from $91.21 per Bbl WTI for the year ended December 31, 2012 to $96.91 per Bbl WTI Cushing for the year ended December 31,
2013. Included in this amount were upward price and performance revisions of 6.6 MMBoe in the Piceance Basin, 3.1 MMBoe in the DJ Basin and 0.3 MMBoe in the Powder River Basin, offset by a 1.1 MMBoe downward engineering revision in the Uinta Oil Program due to lower than predicted performance in some of the wells drilled in the Blacktail Ridge and Lake Canyon areas in 2012. The proved undeveloped reserves from December 31, 2012 that remained in the proved undeveloped reserves category at December 31, 2013 were 42.7 MMBoe.
At December 31, 2012, our proved undeveloped reserves were 71.2 MMBoe. At December
31, 2011, our proved undeveloped reserves were 111.6 MMBoe. During 2012, 22.8 MMBoe, or 20.4% of our December 31, 2011 proved undeveloped reserves (179 wells), were converted into proved developed reserves and required $362.2 million of drilling and completion capital and $45.6 million of facilities capital. These wells produced 3.9 MMBoe in 2012. During 2012, we added 17.8 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. During 2012, 20.2 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans and were either traded, sold or removed. This volume includes 11.9 MMBoe of proved undeveloped reserves sold in the divestiture of our Wind River Basin and Powder River Basin (coalbed methane) properties and a portion of our Piceance Basin properties. Downward engineering and pricing revisions reduced
proved undeveloped reserves by 15.2 MMBoe. Significant pricing revisions occurred in many of our producing areas, particularly our West Tavaputs “dry” natural gas producing field, due to the pricing change from $3.93 per MMBtu CIG for the year ended December 31, 2011 to $2.56 per MMBtu CIG for the year ended December 31, 2012 and from $92.71 per Bbl WTI for the year ended December 31, 2011 to $91.21 per Bbl WTI for the year ended December 31, 2012. Included in this amount were downward price and performance revisions of 21.1 MMBoe at the West Tavaputs natural gas field. Beginning in 2012, production performance from our 2009 to 2011 20-acre infill drilling program in this “tight gas” Mesa Verde/Wasatch formation has lagged behind pre-drilling estimates of the
infill well performance, as we now interpret more interference with the original, 40-acre-spaced, wellbores. A geological and engineering review of the field’s performance has resulted in all remaining proved undeveloped drilling locations, as well as all proved developed producing well estimates to be revised downward to match performance to date. Various other oil and gas fields had a combined negative performance revision of 0.9 MMBoe. Offsetting these, a positive engineering revision in Uinta Oil Program added 6.8 MMBoe in proved undeveloped reserves, resulting from increased operational focus and engineering and geological study. The proved undeveloped reserves from December 31, 2011 that remained in the proved undeveloped reserves category at December 31, 2012 were 54.0 MMBoe.
The
majority of production from the Gibson Gulch area of the Piceance Basin is from the discontinuous fluvial sands of the Williams Fork formation. The resource is consistent across the Gibson Gulch area and results in low variability of estimated ultimate recoveries. The 2011 results of proved undeveloped drilled wells in offsets that are two and three spacing areas from economic producing wells were positive and supported a fourth offset in the proved undeveloped reserve category internal to
the producing area of the field as of December 31, 2011 (four wells, 0.4 MMBoe). New technologies were not used to support these reserves.
The opportunity to use this data to prove more than one direct offset from economic producers is the result of a change in definition of undeveloped oil and gas reserves included in the SEC’s “Modernization of Oil and Gas Reporting” and applied in our December 31, 2009, 2010 and 2011 reserve reports. The proved undeveloped reserves added in the Gibson Gulch area at December 31, 2011 were 3.3 MMBoe, of which 1.8 MMBoe were attributed to the addition of proved undeveloped reserves in locations greater than one spacing unit from economic producers. Acquisitions added 0.4 MMBoe of the 3.3 MMBoe proved undeveloped reserve addition in Gibson Gulch.
At December
31, 2012, we also revised our total proved reserves downward by 21.2 MMBoe due to the combined effects of year end 2012 pricing and the 20-acre infill drilling performance at the West Tavaputs area, described above.
We use our internal reserves estimates rather than the estimates from independent third party engineering firms because we believe that our reserve and operations engineers are more knowledgeable about the wells due to our continual analysis throughout the year as compared to the relatively short term analysis performed by the independent third party engineers. We use our internal reserves estimates on all properties regardless of the positive or negative variance to the independent third party engineers. If a variance greater than 10% occurs at the field level, it may suggest that a difference in methodology or evaluation techniques exists between us and the independent
third party engineers. These differences are investigated by us and the independent third party engineers and discussed with the independent third party engineers to confirm that we used the proper methodologies and techniques in estimating reserves for these fields. These variances also are reviewed with our Reserves and EHS Committee of our Board of Directors. These differences are not resolved to a specified tolerance at the field or property level. In the aggregate, the independent third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates.
The internal review process of our wells and the related reserves estimates, and the related internal controls we utilize, includes but is not limited to the following:
•
A
comparison is made and documented of actual and historical data from our production system to the data in the reserve database. This ensures the accuracy of the production data, which supplies the basis for forecasting.
•
A comparison is made and documented of land and lease record to interest data in the reserve database. This ensures that the costs and revenues will be properly determined in the reserves estimation.
•
A comparison is made of the historical costs (capital and expenses) to the capital and lease operating
costs in the reserve database. Documentation lists reasons for deviation from direct use of historical data. This ensures that all costs are properly included in the reserve database.
•
A comparison is made of input data to data in the reserve database of all property acquisitions, disposals, retirements or transfers to verify that all are accounted for accurately.
•
Natural gas and oil pricing based on the SEC pricing requirements are supplied by the third party independent engineering firm. Natural gas pricing for the
first flow day of every month is collected from Platts Gas Daily Henry Hub price and oil pricing is collected from Bloomberg’s WTI spot price. The average NGL price is based on a percentage of the WTI oil price per barrel.
•
A final check is made of all economic data inputs in the reserve database by comparing them to documentation provided by our internal marketing, land, accounting, production and operations groups. This provides a second check to ensure accuracy of input data in the reserve database.
•
Accurate classification
of reserves is verified by comparing independent classification analyses by our internal reservoir engineers and the third party independent engineers. Discrepancies are discussed and differences are jointly resolved.
•
Internal reserves estimates are reviewed by well and by area by the Manager - Reserves. A variance by well to the previous year-end reserve report is used as a tool in this process. This review is independent of the reserves estimation process.
•
Reserves variances are discussed among the internal reservoir
engineers and the Manager - Reserves. Our internal reserves estimates are reviewed by senior management and the Reserves and EHS Committee of the Board prior to publication.
Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is Earuch F. Broacha. Mr. Broacha is our Reserves and Technology Manager and became responsible for our reserves estimates starting in 2013. Mr. Broacha earned a Bachelor of Science degree in Chemical Engineering and Petroleum Refining from the Colorado School of Mines in 1978. Mr. Broacha has over 35 years’ experience in reserves and economic evaluations, as well as a broad experience in completions, reservoir simulation and petrophysical analyses.
The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Dan Smith and Mr. John Hattner. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. Mr. Smith is a Licensed Professional Engineer in the State of Texas (No. 49093) and has over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum
Engineering. Mr. Hattner has been practicing consulting petroleum geology at NSAI since 1991. Mr. Hattner is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 559) and has over 30 years of practical experience in petroleum geosciences, with over 20 years experience in the estimation and evaluation of reserves. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and
geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
NSAI performed a well-by-well audit of all of our properties and of our estimates of proved reserves and then provided us with its audit report concerning our estimates. The audit completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be the same or different from audit procedures performed by other independent third party engineering firms for other oil and gas companies. NSAI’s audit report does not state the degree of its concurrence with the accuracy of our estimate for the proved reserves attributable to our interest in any specific basin, property or well.
The NSAI audit process of our wells and reserves
estimates is intended to determine the percentage difference, in the aggregate, of our internal net proved reserves estimate and future net revenue (discounted 10%) and the reserves estimate and net revenue as determined by NSAI. The audit process includes the following:
•
The NSAI engineer performs an independent decline curve analysis on proved producing wells based on production and pressure data.
•
The NSAI engineer may verify the production data with the public data.
•
The
NSAI engineer uses his or her individual interpretation of the information and knowledge of the reservoir and area to make an independent analysis of proved producing reserves.
•
The NSAI technical staff will prepare independent maps and volumetric analyses on our properties and offsetting properties. They review our geologic maps, log data, core data, pertinent pressure data, test information and pertinent technical analyses, as well as data from offsetting producers.
•
For the reserves estimates of proved non-producing
and proved undeveloped locations, the NSAI engineer will estimate the potential for depletion by generating a potentiometric surface map, which relates directly to remaining gas-in-place, and analyzing this information with the maps generated earlier in the process.
•
The NSAI engineer will estimate the hydrocarbon recovery of the remaining gas-in-place based upon his/her knowledge and experience.
•
The NSAI engineer does not verify our working and net revenue interests or product price deductions.
•
The
NSAI engineer does not verify our capital costs although he/she may ask for confirming information.
•
The NSAI engineer reviews 12 months of operating cost, revenue and pricing information that we provide.
•
The NSAI engineer confirms the oil and gas prices used for the SEC reserves estimate.
•
NSAI
confirms that its reserves estimate is within a 10% variance of our internal net reserves estimate and estimated future net revenue (discounted 10%), in the aggregate, before an audit letter is issued.
•
The audit by NSAI is not performed such that differences in reserves or revenue on a well level are resolved to any specific tolerance.
The reserves audit letter provided by NSAI states that “in our opinion the estimates of Bill Barrett’s proved reserves and future revenue shown herein are, in the aggregate, reasonable” following an independent estimation of reserve quantities with economic parameters and other factual data provided
by us and accepted by NSAI. The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.
Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown in the Financial Statements should not be construed as the
current market value of the reserves. The 10% discount factor used to calculate present value, which
is required by Financial Accounting Standards Board pronouncements (“FASB”), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
From time to time, we engage NSAI to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its respective employees have no interest in those properties, and the compensation for these engagements is not contingent on NSAI’s estimates of reserves and future cash inflows for the subject properties. During 2013 and 2012, we paid NSAI approximately $550,000 and $446,000, respectively, for auditing our
reserves estimates.
Production and Cost History
The following table sets forth information regarding net production of oil, natural gas and NGLs and certain cost information for each of the periods indicated:
The Gibson Gulch area in the Piceance Basin, the Uinta
Oil Program in the Uinta Basin and the DJ Basin were the only development areas that contained 15% or more of our total proved reserves as of December 31, 2013. The Gibson Gulch area in the Piceance Basin and West Tavaputs area in the Uinta Basin were the only development areas that contained 15% or more of our total proved reserves as of December 31, 2012 and 2011.
(2)
The depreciation, depletion and amortization (“DD&A”) per Boe as calculated based on the DD&A expense and Boe production data presented in the table for the year ended
December 31, 2012 was $16.67. However, the DD&A rate per Boe for the year ended December 31, 2012 of $17.49, as presented in the table above, excludes fourth quarter production of 911 MBoe associated with our properties that were sold as of December 31, 2012.
(3)
General and administrative expense presented herein excludes non-cash stock-based compensation of $15.8 million, $16.4
million and $19.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. If included, these non-cash stock based compensation expenses would have increased general and administrative expense by $1.09, $0.84 and $1.07 per Boe for the years ended December 31, 2013, 2012 and 2011, respectively. General and administrative expense excluding non-cash stock-based compensation is a non-GAAP measure. Non-cash stock-based compensation is combined with general and administrative expense for a total of $64.9 million, $68.7
million and $66.8 million for the years ended December 31, 2013, 2012 and 2011, respectively, in the Consolidated Statements of Operations. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expense. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower non-cash stock-based compensation expense.
Productive Wells
The
following table sets forth information at December 31, 2013 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
Oil
Gas
Basin
Gross
Wells
Net Wells
Gross Wells
Net Wells
Piceance
—
—
956.0
745.0
Uinta
Oil Program
294.0
169.2
5.0
0.9
DJ
150.0
80.9
174.0
122.4
Powder
River Oil
101.0
17.3
4.0
0.8
Other
11.0
4.9
3.0
0.7
Total
556.0
272.3
1,142.0
869.8
Developed
and Undeveloped Acreage
The following table sets forth information as of December 31, 2013 relating to our leasehold acreage.
Developed Acreage (1)
Undeveloped
Acreage (2)
Basin/Area
Gross
Net
Gross
Net
Piceance
11,866
8,675
46,962
41,011
(3)
Uinta
Oil Program
62,362
39,447
157,803
70,795
(4)
DJ
43,786
34,255
130,877
60,672
Powder
River Oil
31,592
10,028
130,447
57,806
Other
13,306
12,054
678,017
479,473
Total
162,912
104,459
1,144,106
709,757
(3)(4)
(1)
Developed
acres are acres spaced or assigned to productive wells.
(2)
Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
(3)
Includes 40,312 gross and 36,281 net acreage associated with the Cottonwood Gulch property.
(4)
Does
not include an additional 153,931 gross and 67,500 net undeveloped acres that are subject to drill-to-earn agreements.
Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We generally have been able to obtain extensions of the primary terms of our federal leases for the period in which we have been unable to obtain drilling permits due to environmental stipulations, pending environmental analysis or related legal challenge. The following table sets forth, as of December 31, 2013, the expiration periods of the gross
and net acres that are subject to leases summarized in the above table of undeveloped acreage.
Includes
207,162 gross and 123,441 net undeveloped acres held by production from other leasehold acreage or held by federal units.
Drilling Results
The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found or economic value. Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
In
general, we serve as operator of wells in which we have a greater than 50% working interest. In addition, we seek to be operator of wells in which we have lesser interests. As operator, we obtain regulatory authorizations, design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or the majority of the other oil field service equipment used for drilling or maintaining wells on the properties we operate. Independent contractors engaged by us provide the majority of the equipment and personnel associated with these activities. We do construct, operate and maintain a majority of the gas gathering facilities associated with our gas fields. We entered into a sale-leaseback transaction in 2012 with respect to the majority of our compression facilities. We lease these facilities from the financial institutions that purchased them and operate these facilities on their behalf. See “Management’s
Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity-Financing Activities-Lease Financing Obligation Due 2020”. We employ drilling, production and reservoir engineers and geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.
Marketing and Customers
We market the majority of the oil production from our operated properties; other than in the Piceance Basin, where we market natural gas, our natural gas and related NGLs are marketed by third parties under percentage of proceeds (“POP”)
contracts. We sell our production to a variety of purchasers under contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. Purchasers include pipelines, processors, marketing companies, local distribution companies and end users. We normally sell production to a relatively small number of customers, as is customary in the development and production business. However, based on where we operate and the availability of other purchasers and markets, we believe that the loss of any of our major purchasers would not have a material adverse effect on our financial condition and results of operations as there are competitive markets available.
During
2013, five customers accounted for 49% of our oil and gas production revenues. During 2012, four customers accounted for 50% of our oil and gas production revenues. During 2011, three customers accounted for 45% of our oil and gas production revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results of operations.
We enter into hedging transactions with unaffiliated third parties for portions of our production revenues to achieve more predictable cash flows and to reduce our exposure to fluctuations in commodities prices. For a more detailed discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations - Overview” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”.
In the Piceance Basin, our natural gas is transported through our own and third party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party gatherer, processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from
the affected properties could be adversely affected. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our natural gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our gas before we can transport it. We contract with third parties to process our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser that has contracted for pipeline capacity. These agreements are subject to the limitations discussed above in this paragraph.
Our oil production is collected in tanks on location and sold to third parties that collect the oil in trucks and transport it to pipelines, rail terminals and refiners. We sell our oil production
to a variety of purchasers under monthly, annual or multi-year terms. Our oil contracts are priced either off of New York Mercantile Exchange (“NYMEX”) or area oil posting with quality, location or transportation differentials.
The following table sets forth information about material long-term firm transportation contracts for pipeline capacity and firm gathering and processing contracts, both of which typically require a demand charge. At the time we entered into these commitments, we estimated that our production, and the production of joint interest owners that we market, would be sufficient to
meet these commitments. Under firm gathering, transportation and processing contracts, we are obligated to deliver minimum daily gas volumes, or pay the respective gathering, transportation or processing fees for any deficiencies in deliveries.
Type of Arrangement
Pipeline System / Location
Deliverable
Market
Gross Deliveries (MMBtu/d)
Term
Firm Gathering
Summit Midstream
Rocky Mountains
Varies
01/11 – 12/20
Firm
Transport
WIC Overthrust (1)
Rocky Mountains
50,000
08/11 – 07/21
Firm Transport
Questar Pipeline
Rocky
Mountains
12,000
11/05 – 10/15
Firm Transport
Rockies Express
Northeast
25,000
06/09 – 11/19
Firm
Transport
Ruby Pipeline
West Coast
50,000
08/11 – 07/21
(1)
This contract was entered into
in conjunction with the Ruby Pipeline contract; and therefore has an end date of 10 years from the in-service date of the Ruby Pipeline.
Hedging Activities
We have an active commodity hedging program, the purpose of which is to mitigate the risks of volatile prices of oil, natural gas, and NGLs. Typically, we intend to hedge approximately 50% to 70% of our oil, natural gas and NGLs production
on
a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments with counterparties that we believe are creditworthy. We currently have hedged approximately 65% of our expected 2014 production and 20% of our expected 2015 production at price levels that provide some economic certainty to our capital investments. To date 9 of our 17 lenders (or affiliates of lenders) under our credit facility are also hedging counterparties. We are not required to post collateral for these hedges other than the security for our credit facility. For additional information on our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”.
Competition
The oil and gas industry is intensely competitive, and we compete with a large number of other companies, some of which have greater resources. Many of these companies not only explore for and produce oil, natural gas and NGLs, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies are able to pay more for productive oil, natural gas and NGLs properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil, natural gas and NGLs market prices. Our larger or integrated competitors are better able to absorb the burden of existing, and any changes to, federal, state, local
and Native American tribal laws and regulations than we can, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil, natural gas and NGLs properties.
Title to Properties
As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved developed reserves. Prior to the commencement of drilling operations
on those properties, we conduct a thorough title examination and perform curative work for significant defects. To the extent title opinions or other investigations reflect title defects on those properties; we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we utilize methods consistent with practices customary in the oil and gas industry and that our practices are adequately designed to enable us to acquire satisfactory title to our producing properties. Prior to completing an acquisition of producing oil and gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil, natural
gas and NGLs properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of our properties or affect the carrying value of the properties.
Seasonal Nature of Business
Generally, but not always, the demand for natural gas decreases during the spring and fall months and increases during the summer and winter months. Seasonal anomalies such as mild winters or cool summers sometime lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during lower demand periods. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling
and producing activities and other oil and natural gas operations in certain areas of the Rockies. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.
Environmental Matters and Regulation
General. Our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our operations are subject to the same environmental laws and regulations as other companies in the oil and gas exploration and production industry.
These laws and regulations:
•
require the acquisition of various permits before drilling commences;
•
require the installation of expensive pollution control equipment;
•
restrict the types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities;
limit or prohibit drilling activities on lands lying within environmentally sensitive areas, wilderness, wetlands and other protected areas;
•
require measures to prevent pollution from
current operations, such as materials and waste management, transportation and disposal requirements;
•
require measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;
•
impose substantial penalties for any non-compliance with federal, state and local laws and regulations;
•
impose
substantial liabilities for any pollution resulting from our operations;
•
with respect to operations affecting federal lands or leases, require time consuming environmental analysis with uncertain outcomes;
•
expose us to litigation by environmental and other special interest groups; and
•
impose
certain compliance and regulatory reporting requirements.
These laws, rules and regulations may also restrict the rate of oil, natural gas and NGLs production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost and timing of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.
We believe that we substantially are in compliance with, and have complied with, all applicable environmental
laws and regulations. We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with governmental regulations. We believe that our continued compliance with existing requirements have been accounted for and will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of any more stringent future laws and regulations at this time. For the year ended December 31, 2013, we did not incur any material capital expenditures for remediation or retrofit of pollution control equipment at any of our facilities.
The
environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:
National Environmental Policy Act. Oil, natural gas and NGLs exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of the Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and project alternatives. If impacts are considered significant, the agency will prepare a more detailed Environmental Impact Statement. These environmental
analyses are made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that trigger the requirements of NEPA. Certain federal permits on non-federal lands may also trigger NEPA requirements. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.
Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and on the disposal of non-hazardous wastes.
Under the oversight of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with RCRA or corresponding state programs. RCRA also imposes cleanup liability related to the mismanagement of regulated wastes. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy are currently exempt from regulation under the hazardous waste provisions of RCRA, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.
Indeed, legislation has been proposed from time to time in Congress to reverse the exemption.
We believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we have held, and continue to hold, all necessary and up-to-date approvals, permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes strict, joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be potentially responsible for a release or threatened release of a “hazardous substance” into the environment. These persons may include current and past owners or operators of a disposal site, or site where the release or threatened release of a “hazardous substance” occurred, and companies that disposed of or arranged for the disposal of the hazardous substance at such sites. Under CERCLA, such persons may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims under CERCLA and/or state common law for cleanup costs, personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, could be subject to CERCLA. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such “hazardous substances” have been released.
Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous
state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters, stormwater and other oil and gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These prescriptions also prohibit the discharge of dredge and fill material in regulated waters, including jurisdictional wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. It is anticipated that within the next two years, a federal rulemaking will be held to revise the definition of a regulated “water of the United States”.
This rulemaking may expand the definition of “water of the United States” to include certain waters, including wetlands, not currently regulated. This definition would subject those waters to permitting under the Clean Water Act, including requiring permits under Section 404 of the Clean Water Act for wetlands development. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with the terms thereof. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development.
Air Emissions. The Federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits
and the imposition of other requirements. Most of our facilities are now required to obtain permits before work can begin, and existing facilities are often required to incur capital costs in order to maintain compliance with those permits. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. The EPA has deemed carbon dioxide (“CO2”) and other greenhouse gases to be a danger to public health, which is leading to regulation in a manner similar to other pollutants. The EPA now requires reporting of greenhouse gases, such as CO2 and methane, from operations. The EPA also issued air requirements specific to the oil and gas industry, including air standards for natural gas wells that are hydraulically fractured. The state of Colorado is in the process of an air quality rulemaking for state oil and gas operations that could result in state air regulations that are more stringent
than those imposed by EPA, including regulating methane emissions. The rulemaking will conclude in February 2014. These state and federal regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining permits has the potential to delay the development of oil and natural gas projects.
Climate Change. The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February 2005 and requires
all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The United States has not ratified the Protocol, and the U.S. Congress has not passed proposed legislation directed at reducing greenhouse gas emissions. However, there is increasing public pressure from environmental groups and some states for the United States to develop a national program for regulating greenhouse gas emissions, and several states have already adopted regulations or announced initiatives focused on decreasing or stabilizing greenhouse gas emissions associated with industrial activity, primarily CO2 emissions from power plants. The EPA has also taken certain regulatory actions to address issues related to climate change. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely CO2 and methane, and future restrictions on the combustion of fossil fuels or the
venting of natural gas could impact our future operations. Our operations are not currently adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future
laws or regulations addressing greenhouse gas emissions could impact our business. However, future laws or regulations could result in substantial expenditures or reduced demand for oil or natural gas.
Homeland Security. Legislation continues to be introduced in Congress, and development of regulations continues in the
Department of Homeland Security and other agencies, concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
Other Regulation of the Oil and Gas Industry
The oil and gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, federal, state, local, and Native American
tribes are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
Drilling and Production. Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native
American tribes also regulate one or more of the following:
•
the location of wells and surface facilities;
•
the method of drilling and casing wells;
•
the rates of production or “allowables”;
•
the
surface use and restoration of properties upon which wells are drilled and other third parties;
•
wildlife management and protection;
•
the protection of archeological and paleontological resources;
•
property mitigation measures;
•
the
plugging and abandoning of wells; and
•
notice to, and consultation with, surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws can establish maximum rates of production from oil and
natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state and Native American tribe generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
Hydraulic Fracturing. Our completion operations are subject to regulation, which may increase in the short- or long-term. The well completion technique known as hydraulic fracturing is used to stimulate production of natural gas and oil and has come under increased scrutiny by the environmental community, and local, state and federal jurisdictions. Hydraulic fracturing
involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate oil and natural gas production. We use this completion technique on substantially all our wells.
Under the direction of Congress, the EPA has undertaken a study of the effect, if any, of hydraulic fracturing on drinking water and groundwater. The EPA has also announced its plan to propose pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations. Congress may consider legislation to amend the Federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have issued similar disclosure rules. Several environmental
groups have also petitioned the EPA to extend release reporting requirements under the Emergency Planning Community Right-to-Know Act to the oil and gas extraction industry. In addition, the Department of the Interior has proposed expanded or new regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes many of the lands on
which we conduct or plan to conduct operations. Furthermore, moratoria on hydraulic fracturing have been imposed in certain localities where we do not have operations and legislation has been proposed at local, state and federal levels.
Natural
Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale or resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.
FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive
for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes may have
on our natural gas-related activities.
Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering services, which occur upstream of jurisdictional transmission services, are regulated by state agencies. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.
Operations on Native American Reservations. A portion of our leases in the Uinta Basin are, and some of our future leases in this and
other areas may be, regulated by Native American tribes. In addition to regulation by various federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations applies to lessees, operators and other parties within the boundaries of Native American reservations. Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service, the Bureau of Indian Affairs, the Bureau of Land Management, or BLM, and the EPA, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, tribal employment and tribal contractor preferences and numerous other matters.
Native American tribes are subject
to various federal statutes and oversight by the Bureau of Indian Affairs and Bureau of Land Management. However, each Native American tribe is a sovereign nation and has the right to enact and enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native American tribal members and numerous other conditions that apply to lessees, operators and contractors conducting operations within the boundaries of a Native American reservation. Further, lessees and operators within a Native American reservation are subject to the Native American tribal court system, unless there is a specific waiver of sovereign immunity by the Native American tribe allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal
or state court.
Therefore, we are subject to various laws and regulations pertaining to Native American tribal surface ownership, Native American oil and gas leases, fees, taxes and other burdens, obligations and issues unique to oil and gas ownership and operations within Native American reservations. One or more of these requirements, or delays in obtaining necessary approvals or permits pursuant to these regulations, may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project on those lands.
Employees
As of January 24, 2014,
we had 258 employees of whom 164 work in our Denver office and 94 work in our field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.
As of December 31,
2013, we leased approximately 81,833 square feet of office space in Denver, Colorado at 1099 18th Street, where our principal offices are located. The lease for our Denver office expires in March 2019. We also own field offices in Roosevelt, Utah and Silt, Colorado, and we lease a field office in Greeley, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.
We make available free of charge through our website
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC via EDGAR and posted at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines and the charters of our Audit Committee, Compensation Committee, Reserves and EHS Committee and Nominating and Corporate Governance Committee are posted on our website at http://www.billbarrettcorp.com and are available in print free of charge to any stockholder who requests them. Requests should be sent
by mail to our corporate secretary at our principal office at 1099 18th Street, Suite 2300, Denver, 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.
Annual CEO Certification
As required by New York Stock Exchange rules, on May 13, 2013, we submitted an annual certification signed by our Chief Executive Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.
Item
1A.
Risk Factors.
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or that we currently consider immaterial also may adversely affect our Company.
Risks Related to the Oil and Natural Gas Industry and Our Business
Our
drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have acquired significant amounts of unproved property in order to attempt to further our exploration and development efforts. Drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. From time to time, we may seek industry partners to help mitigate our risk on certain exploration prospects. We cannot guarantee that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed,
that new wells drilled by us in prospects that we pursue will be productive, that we will recover all or any portion of our investment in such unproved property or wells, or that we will succeed in bringing on additional partners.
Drilling for oil, natural gas and NGLs may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. We rely to a significant extent on seismic data and
other advanced technologies in identifying unproved property prospects and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether oil, natural gas or NGLs are present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Drilling
results in our plays may be more uncertain than in other plays that are more mature and have longer established drilling and production histories, and we can provide no assurance that drilling and
completion techniques that have proven to be successful in other formations to maximize recoveries will be ultimately successful when used in our prospects. As a result, we may incur future dry hole costs and or impairment charges due to any of these factors.
Oil and gas prices are volatile and a decline in oil, natural gas and natural gas liquids prices can significantly affect our financial results, impede our growth and result in downward adjustments in our estimated proved oil and gas reserves.
Our revenue, profitability and cash flow depend upon the prices and demand for oil, natural gas and NGLs. The markets for these commodities are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil, natural
gas and NGLs prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil, natural gas and NGLs may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
•
the domestic and foreign supply of oil, natural gas and NGLs;
•
economic conditions in the United States, and the level of consumer product demand;
•
domestic
and foreign governmental regulations;
•
variations between product prices at sales points and applicable index prices;
•
overall domestic and global economic conditions;
•
political and economic conditions in oil producing countries, including the Middle East and South America;
•
the
ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
•
weather conditions;
•
technological advances affecting energy consumption;
•
proximity and capacity of oil and gas pipelines, refineries and other transportation
and processing facilities; and
•
the price and availability of alternative fuels.
Lower oil, natural gas and NGLs prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil, natural gas and NGLs that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration or development results deteriorate, successful efforts accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value
of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.
Substantially all of our producing properties are located in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.
Our operations have been focused on the Rockies, which means our current producing properties and new drilling opportunities
are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil, natural gas and NGLs produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation and processing, and any resulting delays or interruptions of production from existing or planned new wells.
We are subject to complex federal, state, tribal, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business and the recording of proved reserves.
Our
exploration, development, production and marketing operations are subject to extensive environmental regulation at the federal, state and local levels including those governing emissions to air, wastewater discharges, hazardous and solid wastes, remediation of soil, protection of surface and groundwater, and preservation of natural resources. In addition, a portion of our leases in the Uinta Basin are, and some of our future leases may be, regulated by Native American tribes. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties, including the assessment of natural resource
damages. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells and related facilities. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to state regulation of oil and natural gas production and Native American tribes conservation practices and protection of correlative rights. These
regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling and other permits from state, local and Native American tribal authorities. Delays in obtaining regulatory approvals or drilling and other permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs, could have a material adverse effect on our ability to explore on or develop our properties. In addition, if we do not reasonably believe that we can obtain the drilling permits in a timely fashion covering locations for which we recorded proved undeveloped reserves, we may be required to write down the level of our proved reserves. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations
and, consequently, adversely affect our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells, larger operating areas and other aspects of their businesses. See “Items 1 and 2. Business and Properties - Business - Operations - Environmental Matters and Regulation” and “Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry”.
Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could prohibit certain projects or result in materially increased costs and additional operating restrictions or delays because of the significance of hydraulic fracturing in our business.
Hydraulic
fracturing is a well completion practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Nearly all of our future drilling projects will require hydraulic fracturing. If the hydraulic fracturing process is prohibited or significantly regulated or restricted, we would lose the ability to (i) drill and complete the projects for such proved reserves and (ii) maintain the associated acreage, which would have a material adverse effect on our future business, financial condition, operating results and prospects.
The hydraulic fracturing process is currently regulated by state oil and gas commissions, although local initiatives have been proposed to further regulate or ban the process. The EPA, asserting
its authority under the Safe Drinking Water Act (“SDWA”), issued a draft guidance that proposes to require facilities to obtain permits when using diesel fuel in hydraulic fracturing operations. That guidance was issued for public review and comment in 2012 and is expected to be finalized in 2014. The U.S. Energy Policy Act of 2005, which generally exempts hydraulic fracturing from regulation under the Underground Injection Control program of the SDWA, prohibits the use of diesel fuel in the fracturing process without an Underground Injection Control (“UIC”) permit. Industry groups have filed suit challenging the EPA's recent decisions and, thus, in violation of the notice-and-comment rulemaking procedures of the Administrative Procedure Act. In November 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed
to generate future data. A final report is expected in late 2014.
In 2011, a committee of the House of Representatives announced its findings from a year-long investigation of hydraulic fracturing practices and urged the enactment of legislation that would mandate more stringent regulation of the hydraulic fracturing industry. Further, certain members of Congress have called upon: (i) the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; (ii) the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and (iii) the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves
from shale formations, as well as uncertainties associated with those estimates.
The Shale Gas Subcommittee of the Secretary of Energy Advisory Board released a report on August 11, 2011, proposing recommendations to reduce the potential environmental impacts from shale gas production. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism. In 2012 and 2013 the U.S. Department of the Interior proposed federal regulations to require the disclosure of the chemicals used in the fracturing process on public lands, along with other regulations relating to oil and gas production on federal lands. These proposed regulations could serve as a model for state regulation regarding
the process.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to regulations adopted by the Colorado Oil and Gas Conservation Commission (“COGCC”) and put into effect in 2012, the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the COGCC and the public. In addition to state law, local land use restrictions, such as city ordinances, may
restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.
The adoption of these or any other new laws or regulations that significantly restrict hydraulic fracturing could make it more difficult or costly for us to drill and produce from conventional or tight formations as well as make it easier for third parties opposing drilling in general or the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. These developments, as well as
new laws or regulations, could cause us to incur delays, substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal, state or local legislation or regulations governing hydraulic fracturing are enacted or adopted.
Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.
Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business.
Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil, natural gas and NGLs production depends on a number of factors, including the demand for and supply of oil and natural gas
and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and refineries owned and operated by third parties. Our Uinta oil production has a higher paraffin content which limits the number of refiners able to purchase it as feedstock. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.
We may incur substantial losses and be subject to substantial
liability claims as a result of our oil and gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured or underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
•
environmental
hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;
•
abnormally pressured or structured formations;
•
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
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fires,
explosions and ruptures of pipelines;
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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:
damage to and destruction of property and equipment;
•
damage to natural resources due to underground migration of hydraulic fracturing fluids or other fluids or gases;
•
pollution
and other environmental damage, including spillage or mishandling of recovered hydraulic fracturing fluids and produced water;
•
regulatory investigations and penalties;
•
suspension of our operations; and
•
repair and remediation costs.
We
have elected, and may in the future elect, not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. For example, we do not carry business interruption insurance for these reasons. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations and overall financial condition.
Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil, natural gas and NGL reserves.
The oil and gas industry is capital
intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with sales of our equity and debt securities, proceeds from bank borrowings, sales of properties and cash generated by operations. We intend to finance our capital expenditures with cash flow from operations, sale of properties and our existing financing arrangements. Our cash flow from operations and access to capital is subject to a number of variables, including:
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our proved reserves;
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the
level of oil, natural gas and NGLs we are able to produce from existing wells;
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the prices at which oil, natural gas and NGLs are sold;
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the costs required to operate production;
•
our ability to acquire, locate and produce new reserves;
•
global
credit and securities markets;
•
the ability and willingness of lenders and investors to provide capital and the cost of that capital; and
•
the interest of buyers in our properties and the price they are willing to pay for properties.
If our revenues or the borrowing base under our credit facility decreases as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for
any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. We may, from time to time, need to seek additional financing. Our credit facility and senior note indentures place certain restrictions on our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing.
If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in
turn could lead to a possible loss of properties and a decline in our oil, natural gas and NGLs reserves as well as our revenues and results of operations.
Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGLs prices,
costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas and NGLs from these or any other potential drilling locations. As such, our actual drilling activities may differ materially from those presently identified, which could adversely affect our business.
Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed.
The oil and gas industry is
intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for, develop and produce oil, natural gas and NGLs, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies are able to pay more for producing oil, natural gas and NGLs properties and exploration and development prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil, natural gas and NGLs market prices. Our larger or integrated competitors are better able than we are to absorb the burden of existing and any changes to federal, state, local and Native American tribal laws and regulations than we are, which could adversely affect our competitive position.
Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for producing properties and exploration and development prospects.
The ability of our lenders to fund their lending obligations under our revolving credit facility may be limited, which would affect our ability to fund our operations.
Our revolving credit facility has commitments from 17 lenders. If credit markets become turbulent as a result of an economic downturn, delayed economic recovery or other factors, our lenders may become
more restrictive in their lending practices or may be unable to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and potentially losses.
A U.S. and global economic downturn could have a material adverse effect on our business and operations.
Any or all of the following may occur as a result if a crisis arises in the global financial and securities markets and resulting economic downturn:
•
The
economic slowdown could lead to lower demand for oil and natural gas by individuals and industries, which in turn has resulted and could continue to result in lower prices for the oil and natural gas sold by us, lower revenues and possibly losses. This is exacerbated by increases in gas supply resulting from increases in U.S. gas production.
•
The lenders under our revolving credit facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading
to declining production and possibly losses.
•
We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower production levels and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.
•
The
losses incurred by financial institutions as well as the insolvency of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy or being placed in conservatorship or receivership may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially, adversely affected.
•
Our credit facility bears floating interest rates based on the London Interbank
Offer Rate, or LIBOR. As banks were reluctant to lend to each other to avoid risk, LIBOR increased to unprecedented spread levels in 2008. Such increases caused and may in the future cause higher interest expense for unhedged levels of LIBOR-based borrowings.
•
Our credit facility requires the lenders to redetermine our borrowing base semi-annually. The redeterminations are based on our proved reserves and hedge position based on price assumptions that our lenders require us to use to calculate reserves pursuant to the credit facility. The lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base due to lower commodities and futures prices and our
borrowing base could be reduced. This would reduce our funds available to borrow.
Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.
•
Bankruptcies
of purchasers of our oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these assumptions will materially affect the quantities of our reserves.
Underground accumulations of oil, natural gas and NGLs cannot be measured in an exact way. Oil, natural gas and NGLs reserve engineering requires estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGLs prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures
may be incorrect.
Our estimates of proved reserves are determined at prices and costs at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates of reserves. We prepare our own estimates of proved reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see “Items 1 and 2. Business and Properties-Oil and Gas Data-Proved Reserves” and “Supplementary Information to Consolidated Financial Statements-Supplementary Oil and Gas Information (unaudited)-Analysis of Changes in Proved Reserves” in this Annual Report on Form 10-K.
Unless
we replace our oil, natural gas and NGLs reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
Producing oil, natural gas and NGL reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil, natural gas and NGL reserves and production and, therefore, our cash flow and income are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current
and future production at acceptable costs.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil, natural gas and NGLs, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons. We are employing 3C 3-D seismic technology to evaluate certain of our projects. The implementation and practical use of 3C 3-D seismic technology is relatively new, unproven and unconventional, which can lessen its
effectiveness, at least in the near term, and increase our costs. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.
We often gather 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking
option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3-D data without having an opportunity to attempt to benefit from those expenditures.
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil, natural gas and NGLs operations in the Rockies are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas on federal lands, drilling and other oil, natural gas and NGLs
activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.
One of our strategies is to capitalize on opportunistic acquisitions of oil, natural gas and
NGLs reserves. Our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remaining properties for reserve potential. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.
Our
hedging activities could result in financial losses or could reduce our income.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a portion of our production revenues. Hedging arrangements for a portion of our production revenues expose us to the risk of financial loss in some circumstances, including when:
•
there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
•
there
is a change in the mark to market value of our derivatives; or
•
the counterparty to the hedging contract defaults on its contractual obligations.
In addition, these types of hedging arrangements limit the benefit we would receive from increases in commodities prices and may expose us to cash margin requirements if we hedge with counterparties who are not parties to our credit facility.
Our counterparties are financial institutions that are lenders under our
credit facility or affiliates of such lenders. The risk that a counterparty may default on its obligations was heightened by the financial sector crisis of 2008-2009, and losses incurred by many banks and other financial institutions, including some of our counterparties or their affiliates. These losses may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which would reduce our revenues from hedges at a time when we are also receiving a lower price for our production revenues, thus triggering the hedge payments. As a result, our financial condition could be materially adversely affected.
Federal legislation may decrease our ability, and increase the cost, to enter into hedge transactions.
The Dodd-Frank Wall Street Reform and Consumer Protective
Act (“Dodd-Frank”) was signed into law in July 2010. Dodd-Frank regulates derivative transactions, including our commodity derivative swaps. Derivatives final rules were enacted in 2012 and the effect of such rules on our business is currently uncertain. However, as a commercial end user using derivatives to manage commercial risks, we are exempt from posting collateral requirements and mandatory trading on a centralized exchange. We expect to be able to continue to trade with our counterparties, which all are or have been lenders or affiliates of lenders in our credit facility, albeit with a separate capitalized subsidiary of the lender. We expect that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased capital costs of bank subsidiaries. Decreasing our ability to enter into hedging transactions would expose
us to additional risks related to commodity price volatility and impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from oil, natural gas and NGLs sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil, natural gas and NGLs hedging arrangements expose us to credit
risk in the event of nonperformance by counterparties. An economic downturn, a delayed economic recovery and the European sovereign debt crisis further increase these risks.
We face risks related to rating agency downgrades.
If one or more rating agencies downgrades our outstanding debt, raising debt capital could become more difficult and more costly and we may be required to provide collateral or other credit support to certain counterparties. Providing credit support increases our costs and can limit our liquidity.
Compliance
with EPA regulations is expected to become increasingly costly and may lead to our inability to obtain permits necessary to construct and operate new facilities.
The EPA regulates the level of ozone in ambient air and may propose to lower the allowed level of ozone in the future. Because of climate processes, most of the Rockies, where we operate, have higher levels of ozone. As a result of these existing and possible more stringent standards, we may not be able to obtain permits necessary to construct and operate new facilities, or, if we obtain the permits, the added costs to comply with the permit requirements could substantially increase our operating expenses, which would reduce our profits or make certain operations uneconomical.
Possible additional regulation related to global warming
and climate change could have an adverse effect on our operations and demand for oil and gas.
Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases”, including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February 2005 and requires all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The United States has not ratified the Protocol, and the U.S. Congress has not passed proposed legislation directed at reducing greenhouse gas emissions. However, there is increasing public pressure from environmental groups and some states for the United States to develop a national program for regulating
greenhouse gas emissions, and several states have already adopted regulations or announced initiatives focused on decreasing or stabilizing greenhouse gas emissions associated with industrial activity, primarily CO2 emissions from power plants. The EPA also has taken certain regulatory actions to address issues related to climate change. Passage of state or federal climate control legislation or other regulatory initiatives or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for oil and gas.
Possible additional regulation could have an adverse effect on our operations.
Proposed energy legislation and new regulations, driven in
part by the Macondo oil spill in the Gulf of Mexico in 2010, could limit our ability to operate on federal lands, delay access to federal lands, and increase the cost of our operations. Previous proposed legislation included the Consolidated Land, Energy, and Aquatic Resources Act (CLEAR), the Clean Energy Jobs and Oil Company Accountability Act, the Blowout Prevention Act, and public land leasing reforms. The inability to access federal lands, as well as delays and the increased cost of operating on federal lands could result in losses of revenues, increased costs and devaluing of our assets.
Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.
As an oil and natural gas producer, we face various security threats, including
cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize,
they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities, essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
Provisions in our certificate of incorporation and bylaws
and Delaware law make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.
Delaware corporate law and our current certificate of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:
•
giving the board the exclusive right to fill all board vacancies;
•
requiring
special meetings of stockholders to be called only by the board;
•
requiring advance notice for stockholder proposals and director nominations;
•
prohibiting stockholder action by written consent;
•
prohibiting cumulative voting in the election of directors; and
•
allowing
for authorized but unissued common and preferred shares, including shares used in our shareholder rights plan.
These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.
Risks Related to our Senior Notes, Convertible Notes, Lease Financing Obligations and Amended Credit Facility
We
may not be able to generate enough cash flow to meet our debt obligations, including our obligations and commitments under our senior notes, our convertible senior notes, our lease financing obligations and our revolving credit facility.
We expect our earnings and cash flow could vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may be insufficient to meet our debt obligations and commitments, including our 5% Convertible Senior Notes due 2028 (“Convertible Notes”), our 7.625% Senior Notes due 2019 (“7.625% Senior Notes”), our 7.0% Senior Notes due 2022 (“7.0% Senior Notes”), our lease financing obligations, and our revolving credit facility (“Amended Credit Facility”). Any
insufficiency could negatively impact our business. A range of economic, competitive, business, and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to repay our debt. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.
As of December 31, 2013, the total outstanding principal amount of our total indebtedness was approximately $983.7 million, and we had approximately $484.0 million in additional borrowing capacity under our Amended Credit Facility, which, if borrowed, would
be secured debt effectively senior to the Senior Notes and Convertible Notes to the extent of the value of the collateral securing that indebtedness. The borrowing base is dependent on our proved reserves and was, as of December 31, 2013, $625.0 million based on our June 30, 2013 proved reserves, adjusted for the sale of our West Tavaputs properties, and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. As of December 31, 2013, the outstanding principal balance under our Amended Credit Facility was $115.0 million.
If
we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake one or more alternative financing plans, such as:
•
refinancing or restructuring our debt;
•
selling assets;
•
reducing or delaying capital investments; or
•
seeking
to raise additional capital.
However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.
Our debt could have important consequences. For example, it could:
•
increase our vulnerability to general
adverse economic and industry conditions;
limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;
•
limit
our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•
impair our ability to obtain additional financing in the future; and
•
place us at a competitive disadvantage compared to our competitors that have less debt.
In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our convertible
notes and our senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.
Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.
Our Amended Credit Facility contains a number of significant covenants in addition to covenants restricting the incurrence of additional debt. Our Amended Credit Facility requires us, among other things, to maintain certain financial ratios or reduce our debt. These restrictions also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary
corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indenture governing the notes and our Amended Credit Facility impose on us.
Our Amended Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Amended Credit Facility. Any increase in the borrowing base requires the consent of the lenders holding 98% of the commitments. If the required lenders do not agree on an increase, then the borrowing base
will be the lowest borrowing base acceptable to the required number of lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under the Amended Credit Facility.
A breach of any covenant in our Amended Credit Facility or the agreements and indentures governing our other indebtedness would result in a default under that agreement or indenture after any applicable grace periods. A default, if not waived, could result in acceleration
of the debt outstanding under the agreement and in a default with respect to, and an acceleration of, the debt outstanding under other debt agreements. The accelerated debt would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt or take other actions to pay accelerated debt. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
Risks Relating to Tax
We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result
of future legislation.
President Obama has proposed eliminating certain key U.S. federal income tax deductions and credits currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to:
•
the repeal of the percentage depletion allowance for oil, natural gas and NGL properties;
•
the elimination of current deductions for intangible drilling
and development costs;
•
the elimination of the deduction for certain U.S. production activities; and
•
an extension of the amortization period for certain geological and geophysical expenditures.
It is unclear whether any of the foregoing changes will be enacted or how soon any such changes could become effective. Any such change could negatively impact our financial condition and results of operations by increasing
the costs we incur, which in turn could make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.
We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.
Market
for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market For Registrant’s Common Equity
Our common stock is listed on the New York Stock Exchange under the symbol “BBG”.
The range of high and low sales prices for our common stock for the two most recent fiscal years as reported by the New York Stock Exchange was as follows:
High
Low
2013
First
Quarter
$
21.64
$
15.50
Second Quarter
24.23
17.78
Third
Quarter
25.47
20.34
Fourth Quarter
30.69
24.08
2012
First
Quarter
$
36.44
$
25.00
Second Quarter
26.38
15.42
Third
Quarter
27.01
18.10
Fourth Quarter
26.13
16.84
On January 24,
2014, the closing sales price for our common stock as reported by the NYSE was $28.16 per share.
Holders. On December 31, 2013, the number of holders of record of our common stock was 120.
Dividends. We have not paid any cash dividends since our inception. Because we anticipate that all earnings will be retained for the development of our business and our Amended Credit Facility and Senior Notes prohibit the payment of cash dividends, we do not expect that any cash dividends will be paid on our common stock for the foreseeable future.
Unregistered
Sales of Securities. There were no sales of unregistered equity securities during the year ended December 31, 2013.
Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2013:
Period
Total
Number
of
Shares (1)
Weighted
Average Price
Paid Per
Share
Total Number of Shares
(or Units) Purchased as
Part of Publicly
Announced Plans or
Programs
Maximum Number
(or
Approximate Dollar Value)
of Shares (or Units) that
May Yet be Purchased
Under the Plans or
Programs
October 1 - 31, 2013
500
$
26.03
0
0
November
1 - 30, 2013
3,343
$
27.63
0
0
December 1 - 31, 2013
9,677
$
26.60
0
0
Total
13,520
$
26.83
0
0
(1)
Represents
shares delivered by employees to satisfy the exercise price of stock options and tax withholding obligations in connection with the exercise of stock options and shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of restricted common stock issued pursuant to our employee incentive plans.
As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:
1.
$100
was invested in our common stock on December 31, 2008, and $100 was invested in each of the Standard & Poors 500 Index and the Standard & Poors MidCap 400 Index-Energy Sector at the closing price on December 31, 2008.
2.
Dividends are reinvested on the ex-dividend dates.
The following table presents our selected historical financial data for the years ended December 31, 2013, 2012, 2011, 2010 and 2009. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations” presented elsewhere in this Annual Report on Form 10-K.
Selected Historical Financial Information
The consolidated statement of operations information for the years ended December 31, 2013, 2012 and 2011 and the balance sheet information as of December 31, 2013 and 2012 are derived from our audited consolidated financial statements included elsewhere in this report. The consolidated statement of operations
information for the years ended December 31, 2010 and 2009 and the balance sheet information at December 31, 2011, 2010 and 2009 are derived from audited consolidated financial statements that are not included in this report. The information in this table should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included herein.
Depreciation,
depletion, impairment and amortization
506,326
364,190
388,699
276,281
273,227
Other
non-cash items
(32,600
)
29,281
55,102
101,079
132,885
Change
in assets and liabilities
(15,728
)
(5,617
)
4,840
(10,674
)
24,414
Net
cash provided by operating activities
$
265,265
$
388,436
$
479,348
$
447,188
$
480,744
Capital
expenditures (3)(4)
$
474,031
$
962,573
$
987,341
$
473,268
$
406,420
(1)
Oil,
gas and NGL production revenues include the effects of cash flow hedging transactions.
(2)
Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Consolidated Statements of Operations for a total of $64.9 million, $68.7 million, $66.8 million, $57.8 million and $54.4 million for the years ended December 31, 2013, 2012,
2011, 2010 and 2009, respectively. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expense. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower non-cash stock-based compensation expense.
(3)
Excludes future reclamation liabilities of negative $6.6 million and $7.5
million, $12.1 million, $1.3 million and negative $1.2 million for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $12.2 million, $39.3 million, $21.0 million, $38.2 million and $35.9 million
for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively. Also includes furniture, fixtures and equipment costs of $1.3 million, $6.9 million, $8.9 million, $2.1 million and $2.1 million for the years ended December 31, 2013, 2012, 2011, 2010
and 2009, respectively.
(4)
Not deducted from the amount are $306.3 million, $325.3 million, $2.0 million, $2.9 million and $3.7 million of proceeds received principally from the sale of interests in oil and gas properties during the years ended December 31, 2013, 2012, 2011, 2010
and 2009, respectively.
The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve
risks and uncertainties. See the “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in “Item 1A. Risk Factors” above, which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.
Overview
We develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value by
delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations plans while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices and from the settlement of commodity hedges. Due to current and expected commodity prices for oil, natural gas and NGLs, we are focused on developing oil assets where we have established a long-term inventory of drilling locations. As a result, we have transitioned our portfolio to have a better balance in the mix of oil, natural gas, and NGLs for both production and reserves.
We
were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share.
We are committed to exploring for, developing and producing oil, natural gas and NGLs in a responsible and safe manner. We work diligently with environmental, wildlife and community organizations to ensure that our exploration and development activities are designed with all stakeholders in mind.
While there are currently no unannounced agreements for the acquisition of any material businesses or assets, future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production
and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, sales of properties, other indebtedness, and/or debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.
Beginning January 1, 2013, we modified our gas processing agreements with various processors to take title to NGLs resulting from the processing of our natural gas. Therefore, we report below reserve and production data for oil, natural gas and NGLs for periods after January 1,
2013. This is known as “three streams reporting”. For periods prior to January 1, 2013, we presented our production and reserve data for oil and natural gas, which combined NGLs with the natural gas stream, and did not separately report NGLs. This change impacts the comparability of 2013 with prior periods.
As of January 1, 2014, we are reporting reserves, production and the related metrics in Boe instead if Mcfe, because of our combined exit production rate for 2013 of 58% for oil and NGLs and as we continue to focus on the development of our oil prospects.
Because of our growth through acquisitions and, more recently, development of our properties and sale of non-core properties
in 2012 and 2013, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not indicative of future results.
The following table summarizes the estimated net proved reserves and related Standardized Measure for the years indicated. The Standardized Measure is not intended to represent the current market value of our estimated oil and natural gas reserves.
December 31,
2013 was based on average prices of $96.91 WTI for oil, $3.67 Henry Hub for natural gas and $39.75 for NGLs using the current SEC requirements. December 31, 2012 was based on average prices of $2.56 CIG for natural gas and $91.21 WTI for oil using the current SEC requirements. December 31, 2011 was based on average prices of $3.93 CIG for natural gas and $92.71 WTI for oil.
The
following table summarizes the average sales prices received for oil, natural gas and NGLs, before the effects of hedging contracts, for the years indicated:
Prior
to 2013, NGL volumes and revenues were included within natural gas production data, which impacts the comparability for the two periods presented.
The following table summarizes the average sales prices received for oil, natural gas and NGLs, after the effects of hedging contracts, for the years indicated:
Prior
to 2013, NGL volumes and revenues were included within natural gas production data, which impacts the comparability for the two periods presented.
Commodity prices are inherently volatile and are influenced by many factors outside of our control. We plan our activities and capital budget using what we believe to be conservative sales price assumptions and our existing hedge position. Our strategic objective is to hedge 50% to 70% of our anticipated production on a forward 12-month basis using a combination of swaps and other financial derivative instruments. We currently have hedged approximately 65% of our expected 2014 production and 20% of our expected 2015 production at price
levels that provide some economic certainty to our capital investments. We focus our efforts on increasing oil, natural gas and NGLs reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.
Like all oil and gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil, gas and NGLs production from a typical well naturally decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.
Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. See “ - Trends and Uncertainties - Regulatory Trends” below. The permitting and approval process has been more difficult in recent years than in the past due to more stringent rules, such as those enacted by the COGCC in 2009, and increased activism from environmental and other groups, which has extended the time it takes us to receive permits and other necessary approvals. Because of our relatively small size and concentrated property base, we can be disproportionately disadvantaged by delays in obtaining or failing to obtain
drilling approvals compared to companies with larger or more dispersed property bases. As a result, we may be less able to shift drilling activities to areas
where permitting may be easier, and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.
The following table sets forth selected operating data for the periods indicated:
Year Ended December
31,
Increase (Decrease)
2013
2012
Amount
Percent
($ in thousands, except per unit data)
Operating Results:
Operating
and Other Revenues
Oil, gas and NGL production
$
565,555
$
700,639
$
(135,084
)
(19
)%
Other
2,538
(444
)
2,982
*nm
Total
operating and other revenues
$
568,093
$
700,195
$
(132,102
)
(19
)%
Operating
Expenses
Lease operating expense
$
70,217
$
72,734
$
(2,517
)
(3
)%
Gathering,
transportation and processing expense
67,269
106,548
(39,279
)
(37
)%
Production tax expense
27,172
25,513
1,659
7
%
Exploration
expense
337
8,814
(8,477
)
(96
)%
Impairment, dry hole costs and abandonment expense
238,398
67,869
170,529
*nm
Depreciation,
depletion and amortization
279,775
326,842
(47,067
)
(14
)%
General and administrative expense (1)
49,069
52,222
(3,153
)
(6
)%
Non-cash
stock-based compensation expense (1)
15,833
16,444
(611
)
(4
)%
Total operating expenses
$
748,070
$
676,986
$
71,084
11
%
Production
Data (2):
Oil (MBbls)
3,495
2,687
808
30
%
Natural
gas (MMcf)
52,685
101,486
(48,801
)
(48
)%
NGLs (MBbls)
2,199
—
2,199
*nm
Combined
volumes (MBoe)
14,475
19,601
(5,126
)
(26
)%
Daily combined volumes (Boe/d)
39,658
53,701
(14,043
)
(26
)%
Average
Realized Prices (2)(3):
Oil (per Bbl)
$
82.38
$
84.96
$
(2.58
)
(3
)%
Natural
gas (per MMcf) (4)
4.16
5.07
(0.91
)
(18
)%
NGLs (per Bbl)
28.31
—
28.31
*nm
Combined
(per Boe)
39.35
37.90
1.45
4
%
Average Costs (per Boe):
Lease
operating expense
$
4.85
$
3.71
$
1.14
31
%
Gathering,
transportation and processing expense
4.65
5.44
(0.79
)
(15
)%
Production tax expense
1.88
1.30
0.58
45
%
Depreciation,
depletion and amortization (5)
19.33
17.49
1.84
11
%
General and administrative expense (6)
3.39
2.66
0.73
27
%
*
Not
meaningful.
(1)
Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $64.9 million and $68.7 million for the years ended December 31, 2013 and 2012, respectively, in the Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative
expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.
Prior to 2013, NGL volumes were included within natural gas production data, which impacts the comparability for the two periods presented.
(3)
Average
realized prices shown in the table are net of the effects of all settled commodity hedging transactions related to current period production.
(4)
Natural gas prices for 2012 include the effect of NGL related production and revenue.
(5)
The DD&A per Boe as calculated based on the DD&A expense and production data presented in the table for the year ended December 31, 2012 is $16.67. However, the DD&A rate per Boe for
the year ended December 31, 2012 of $17.49, as presented in the table above, excludes fourth quarter production of 911 MBoe, associated with our properties that were sold as of December 31, 2012.
(6)
Excludes non-cash stock-based compensation expense as described in Note 1 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Consolidated Statements of Operations, were $4.48 and $3.50
for the years ended December 31, 2013 and 2012, respectively.
Production Revenues and Volumes. Historically, we have reported our natural gas production as a single stream of wet gas measured at the well head. Beginning in the first quarter of 2013, we changed our reporting for natural gas volumes to show natural gas and NGL production volumes consistent with title transfer for each product. Effective January 1, 2013, substantially all of our gas processing contracts
were amended to designate title transfer of gas and NGLs processed at the tailgate of each processing plant.
Production revenues decreased to $565.6 million for the year ended December 31, 2013 from $700.6 million for the year ended December 31, 2012. The decrease in production revenues was primarily due to a 26% decrease in production volumes, offset by an increase in average prices. The decrease
in production volumes reduced production revenues by approximately $200.2 million, while the increase in average prices increased production revenues by approximately $65.2 million.
We discontinued hedge accounting as of January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in accumulated other comprehensive income (“AOCI”) as of January 1, 2012 and will remain in AOCI until the underlying transaction occurs. As the underlying transaction occurs, these gains or losses are reclassified from AOCI into oil, gas and NGL production revenues. The amount reclassified to oil, gas and NGL production revenues was a gain of $7.5
million and $81.2 million for the years ended December 31, 2013 and 2012, respectively.
Total production volumes of 14.5 MMBoe for the year ended December 31, 2013 decreased from 19.6 MMBoe for the year ended December 31, 2012. We completed a sale of natural gas assets on December 31,
2012, including 100% of our Wind River Basin and Powder River Basin - Coalbed Methane properties (“PRB-CBM”) and an initial 18% interest in the Gibson Gulch assets in the Piceance Basin that progresses to a 26% interest in 2016 (the “2012 Divestiture”). Lower natural gas commodity prices caused us to discontinue drilling activity in the Piceance Basin and West Tavaputs area in the Uinta Basin in 2012 to concentrate on our oil development programs, which has continued to negatively impact 2013 gas production volumes. These decreases were partially offset by a 30% overall increase in oil production with increases in the Uinta Oil Program, DJ Basin and Powder River Oil Program. Additional information concerning production is in the following table:
Other for 2012 includes PRB–CBM natural gas volumes of 10,888 MMcf, Wind River natural gas production
volumes of 3,913 MMcf and oil production of 18 MBbls.
Hedging Activities. In 2013, approximately 83% of our oil volumes, 92% of our natural gas volumes and 16% of our NGL related volumes were subject to financial hedges, which resulted in a decrease in oil revenues of $0.8 million, partially offset by increases in natural gas revenues of $10.8 million and NGL production revenues of $2.8 million after settlements for all commodity derivatives. Of the gain
on total settlements of $12.8 million for the year ended December 31, 2013, a gain of $7.5 million was included in oil, gas and NGL production revenues and a gain of $5.3 million was included in commodity derivative gain (loss) in the Consolidated Statements of Operations. In 2012, approximately 76% of our oil volumes, 68% of our natural gas volumes (excluding basis only swaps, which were equivalent to 7% of our natural gas volumes), and 23% of our NGL related recoveries were subject to financial hedges, which resulted in an increase in oil revenues
of $15.0 million, of which $3.9 million was included in oil, gas and NGL production revenues, and an increase natural gas revenues of $108.5 million, of which $77.2 million was included in oil, gas and NGL production revenues, after settlements for all commodity derivatives, including basis only and NGL swaps.
Other Operating Revenues. Other operating revenues increased to $2.5 million for the year ended December 31, 2013 from a loss of $0.4 million for the year ended December 31, 2012.
Other operating revenues for 2013 consisted of $0.2 million in net gains realized from the sale of properties and $2.3 million of income from gathering, compression and salt water disposal fees received from third parties. The net realized gains from the sale of properties for the year ended December 31, 2013 related to a loss of $3.1 million from purchase price adjustments on the 2012 Divestiture, offset by a gain of $3.3 million from selldowns of other properties. Other operating revenues for 2012 consisted of a $4.5 million loss on the sale of our natural gas assets including 100% of our Wind River Basin and Powder River Basin coalbed methane assets, and a non-operating working interest in our Piceance Basin development property. This loss was offset by $2.7 million of income from gathering, compression and salt-water disposal
fees received from third parties and $1.4 million from the sale of seismic data.
Lease Operating Expense. Lease operating expense (“LOE”) increased to $4.85 per Boe for the year ended December 31, 2013 from $3.71 per Boe for the year ended December 31, 2012. LOE on a per Boe basis is inherently higher from our oil producing properties such as those in our Uinta Oil and DJ Basin development areas. In addition, the 2012 Divestiture consisted of natural gas
properties with lower LOE per Boe, which contributed to a higher comparative LOE per Boe unit cost in the year ended December 31, 2013.
Gathering, Transportation and Processing Expense. Gathering, transportation and processing (“GTP”) expense decreased to $4.65 per Boe for the year ended December 31, 2013 from $5.44 per Boe for the year ended December 31, 2012. The decrease is primarily due to an increase in oil production for the year ended December
31, 2013, which has lower GTP expense than natural gas as well as the sale of our Powder River- CBM assets as part of the 2012 Divestiture, which had higher GTP expense per Boe compared to our other assets. We have entered into long-term firm transportation contracts for a portion of our gas production from the Piceance and Uinta Basins. From time to time, the Company may sell certain portions of firm capacity on various pipelines, as business or operational conditions warrant, to mitigate our exposure on unused transportation capacity.
Production Tax Expense. Total production taxes increased
to $27.2 million for the year ended December 31, 2013 from $25.5 million for the year ended December 31, 2012. 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 4.9% and 4.1% for the years ended December 31, 2013 and December 31, 2012,
respectively.
Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The increase in the overall production tax rate is consistent with our production increase in areas with higher production tax rates.
Exploration Expense. Exploration expense for the year ended December 31, 2013 was $0.3 million compared to $8.8
million for the year ended December 31, 2012. Exploration expense for the year ended December 31, 2013 consisted of $0.3 million for delay rentals across all basins. Exploration expense for the year ended December 31, 2012 consisted of $7.9 million of geological and geophysical seismic programs and $0.9 million for delay rentals across all basins.
Impairment, Dry Hole
Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $238.4 million for the year ended December 31, 2013 from $67.9 million for the year ended December 31, 2012.
For the year ended December 31,
2013, impairment expense was $226.6 million, abandonment expense was $10.7 million and dry hole expense was $1.1 million. The $226.6 million of impairment expense for the year ended December 31, 2013 included $207.0 million related to proved oil and gas properties and $19.6 million related to unproved oil and gas properties. We recognized $207.0 million of proved impairment expense and $2.5 million of unproved property impairment expense during the year ended December 31, 2013
related to our West Tavaputs properties based upon an analysis of the carrying value of the related properties relative to their estimated fair values. These assets were sold in December 2013. In addition, we recognized $17.1 million of impairment expense related to certain unproved oil and gas properties within exploration projects primarily as a result of no future plans to evaluate the remaining acreage and an estimated market value below our carrying value. The impairment expense contributed substantially to our net loss of $192.7 million for the year ended December 31, 2013.
For the year ended December 31, 2012, impairment expense was $37.3 million, abandonment expense associated
with exploratory drilling locations was $9.6 million and dry hole costs were $21.0 million. The $37.3 million related to impairing certain unproved oil and gas properties within various exploration and development projects primarily as a result of unfavorable market conditions or no future plans to evaluate the remaining acreage. For the year ended December 31, 2012, we did not record any impairment charges related to proved oil and gas properties.
We evaluate the impairment of our proved oil and gas properties on a property-by-property basis annually or whenever events or changes in circumstances indicate a property’s carrying amount may not
be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the property to fair value through a charge to impairment expense.
Unproved oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop existing acreage. We continue to review our acreage position and future drilling plans based on the current price environment. If our attempts to market interests in certain properties to industry partners are unsuccessful, we may record additional leasehold impairments and abandonments in exploration prospects.
Dry hole costs of $1.1 million
for the year ended December 31, 2013 primarily relate to additional costs on wells deemed to be dry holes in 2012. Dry hole costs of $21.0 million for the year ended December 31, 2012 primarily relate to two unsuccessful exploratory natural gas wells in the Paradox Basin and one unsuccessful exploratory well in the Alberta Basin.
Depreciation, Depletion and Amortization. DD&A decreased to $279.8 million for the year ended December 31,
2013 compared with $326.8 million for the year ended December 31, 2012. The decrease of $47.0 million was a result of a 26% decrease in production for the year ended December 31, 2013 compared with the year ended December 31, 2012, offset by an increase in the DD&A rate. The decrease in production accounted for a $89.6 million decrease in DD&A expense, while the overall
increase in the DD&A rate accounted for $42.6 million of additional DD&A expense. The increase in the DD&A rate during the year ended December 31, 2013 was due to an increase in the mix of oil projects in 2013 as compared to 2012, which have higher capital costs per reserve unit compared to natural gas projects, and the sale of properties with lower DD&A rates in the 2012 Divestiture.
Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field to determine a depletion rate for
current production. For the year ended December 31, 2013, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $19.33 per Boe compared with $17.49 per Boe for the year ended December 31, 2012. Future depletion rates will be adjusted to reflect capital expenditures, proved reserve changes and well performance.
General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, decreased
to $49.1 million for the year ended December 31, 2013 from $52.2 million for the year ended December 31, 2012. The decrease of $3.1 million was primarily the result of a 26% decrease in the number of employees as of December 31, 2013 compared to December 31, 2012, due to the Company's divestitures. General and administrative expense, excluding non-cash stock-based
compensation, is a non-GAAP measure. See Note 1 to the table on page 44 for a reconciliation and explanation. On a per Boe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $3.39 in 2013 from $2.66 in 2012, primarily related to the 26% decrease in production from 2013 compared with 2012.
Non-cash charges for stock-based compensation for the years ended December 31, 2013
and 2012 were $15.8 million and $16.4 million, respectively. Non-cash stock-based compensation expense for each of the years ended December 31, 2013 and 2012 related primarily to vesting of our stock option awards and nonvested shares of common stock issued to employees.
Stock options and nonvested equity shares of common stock
$
14,758
$
15,435
Shares issued for 401(k) plan
724
733
Shares
issued for directors’ fees
351
276
Total
$
15,833
$
16,444
Interest
Expense. Interest expense decreased to $88.5 million for the year ended December 31, 2013 from $95.5 million for the year ended December 31, 2012. The decrease for the year ended December 31, 2013 was primarily due to a lower weighted average interest rate as a result of the redemption of our 9.875% Senior Notes on July 15, 2013. Our weighted average interest rate for the year ended December 31,
2013 was 7.2% compared with 8.2% for the year ended December 31, 2012.
Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a loss of $23.1 million for the year ended December 31, 2013 compared to a gain of $72.8 million for the year
ended December 31, 2012. The decrease was primarily due to a decrease in our natural gas hedging contracts as a result of lower natural gas volumes hedged and a large increase in oil futures pricing for the year ended December 31, 2013 compared with December 31, 2012.
The table below summarizes the Company's commodity derivative gains and losses that were recognized in the periods presented:
Realized gain on derivatives not designated as cash flow hedges
$
5,315
$
42,305
Unrealized
gain (loss) on derivatives not designated as cash flow hedges
(28,383
)
30,454
Total commodity derivative gain (loss)
$
(23,068
)
$
72,759
Income
Tax Benefit. Income tax benefit totaled $118.6 million for the year ended December 31, 2013 compared with an income tax expense of $1.6 million for the year ended December 31, 2012, resulting in effective tax rates of 38.1% and 73.8%, respectively. For both the 2013 and 2012 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording stock-based
compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes. The effective tax rate for December 31, 2012 was exceptionally high due to the amount of non-deductible expenses relative to the low operating income coupled with the effect a statutory rate increase had on the Company’s prior year net deferred tax liability. At December 31, 2013, we had approximately $218.0 million of federal tax net operating loss carryforwards, or “NOLs”, which expire through 2033. We also had a federal alternative minimum tax credit carryforward of $0.7 million, which has no expiration date. We believe it is more likely than not that we will use these tax attributes to offset and reduce tax liabilities in future years.
At December 31, 2013, the Company had approximately $5.9 million of state income tax credit carryforwards. We continue to believe it is more likely than not that this deferred tax asset will not be realized, and therefore a valuation allowance is recorded for the state tax credits.
The following table sets forth selected operating data for the periods indicated:
Year Ended December 31,
Increase
(Decrease)
2012
2011
Amount
Percent
($ in thousands, except per unit data)
Operating Results:
Operating
and Other Revenues
Oil, gas and NGL production
$
700,639
$
780,751
$
(80,112
)
(10
)%
Other
(444
)
4,873
(5,317
)
(109
)%
Total
operating and other revenues
$
700,195
$
785,624
$
(85,429
)
(11
)%
Operating
Expenses
Lease operating expense
$
72,734
$
56,603
$
16,131
28
%
Gathering,
transportation and processing expense
106,548
93,423
13,125
14
%
Production tax expense
25,513
37,498
(11,985
)
(32
)%
Exploration
expense
8,814
3,645
5,169
142
%
Impairment, dry hole costs and abandonment expense
67,869
117,599
(49,730
)
(42
)%
Depreciation,
depletion and amortization
326,842
288,421
38,421
13
%
General and administrative expense (1)
52,222
47,744
4,478
9
%
Non-cash
stock-based compensation expense (1)
16,444
19,036
(2,592
)
(14
)%
Total operating expenses
$
676,986
$
663,969
$
13,017
2
%
Production
Data:
Oil (MBbls)
2,687
1,490
1,197
80
%
Natural
gas (MMcf)
101,486
97,856
3,630
4
%
Combined volumes (MBoe)
19,601
17,799
1,802
10
%
Daily
combined volumes (Boe/d)
53,701
48,764
4,937
10
%
Average Realized Prices (2):
Oil
(per Bbl)
$
84.96
$
80.63
$
4.33
5
%
Natural
gas (per MMcf)
5.07
6.46
(1.39
)
(22
)%
Combined (per Boe)
37.90
42.29
(4.39
)
(10
)%
Average
Costs (per Boe):
Lease operating expense
$
3.71
$
3.18
$
0.53
17
%
Gathering,
transportation and processing expense (3)
5.44
5.25
0.19
4
%
Production tax expense
1.30
2.11
(0.81
)
(38
)%
Depreciation,
depletion and amortization
17.49
16.20
1.29
8
%
General and administrative expense (4)
2.66
2.68
(0.02
)
(1
)%
(1)
Non-cash
stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Consolidated Statements of Operations for a total of $68.7 million and $66.8 million for the years ended December 31, 2012 and December 31, 2011, respectively. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with non-cash stock-based compensation expense.
(2)
Average
realized prices shown in the table are net of the effects of all settled commodity hedging transactions related to current period production.
(3)
The DD&A per Boe as calculated based on the DD&A expense and MBoe production data presented in the table for the year ended December 31, 2012 is $16.67. However, the DD&A rate per Boe for the year ended December 31, 2012 of
$17.49, as presented in the table above, excludes fourth quarter 2012 production of 911 MBoe, associated with our properties that were sold as of December 31, 2012.
(4)
Excludes non-cash stock-based compensation expense as described in Note 1 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Consolidated Statements of Operations, were $3.50 and $3.75 for the years ended December 31,
2012 and 2011, respectively.
Production Revenues and Volumes. Production revenues decreased to $700.6 million for the year ended December 31, 2012 from $780.8 million for the year ended December 31, 2011 due to a 19% decrease in oil and natural gas prices on a per Boe basis after the effects of realized cash flow hedges, offset by a 10% increase in production. The decrease in average price reduced production revenues by approximately $144.6 million, and the net increase in production added approximately $64.4 million of production revenues.
The year ended December
31, 2011 included settlements of $99.9 million from financial hedging instruments that were designated as cash flow hedges and excluded those that did not qualify, or were not designated, as cash flow hedges such as basis only and NGL swaps. The settlements from hedging instruments that were not designated as cash flow hedges were included in the line item commodity derivative gain (loss) within other income in the Consolidated Statements of Operations. See “Commodity Derivative Gain (Loss)” below for more information related to the commodity derivative gain (loss) line item. We discontinued hedge accounting effective January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in AOCI effective January 1, 2012 and will remain in AOCI until the underlying transaction occurs. As the underlying transaction occurs,
these gains or losses are reclassified from AOCI into oil, gas and NGL production revenues. The amount reclassified to oil, gas and NGL production revenues was a gain of $81.2 million for the year ended December 31, 2012.
Total production volumes increased to 19.6 MMBoe for the year ended December 31, 2012 from 17.8 MMBoe for the year ended December 31, 2011, primarily due to an 80% increase in oil production for the year ended December 31, 2012. Due to lower natural gas commodity prices in 2012, we discontinued drilling activity in the Piceance Basin and West Tavaputs area in the Uinta Basin
to concentrate on our oil development programs. In addition, we completed a sale of natural gas assets including 100% of our Wind River Basin and Powder River Basin coalbed methane properties, and an initial 18% interest in the Gibson Gulch assets in the Piceance Basin that progresses to a 26% interest in 2016, as of December 31, 2012. Additional information concerning production is in the following table:
Hedging Activities. In 2012, approximately 76% of our oil volumes, 68% of our natural gas volumes (excluding basis-only swaps, which were equivalent to 7% of our natural gas volumes) and 23% of our NGL-related recoveries were subject to financial hedges, which resulted in an increase in oil revenues of $15.0 million, of which $3.9 million was included in the oil, gas and NGL production revenue line item, and an increase in natural gas revenues of $108.5 million, of which $77.2 million was included in the oil, gas and NGL production revenue line item, after settlements for all commodity derivatives, including basis-only and NGL swaps. In 2011, approximately 67% of our natural gas volumes (excluding basis-only swaps, which were equivalent to 7% of our natural gas volumes), 53% of our NGL related recoveries and 66%
of our oil volumes were subject to financial hedges, which resulted in a decrease in oil revenues of $2.0 million and an increase in natural gas revenues of $73.9 million after settlements for all commodity derivatives, including basis-only and NGL swaps. The increase in oil and natural gas hedge related revenues primarily resulted from lower average oil and natural gas prices during the year ended December 31, 2012 as compared to the year ended December 31, 2011.
Other
Operating Revenues. Other operating revenues decreased to a loss of $0.4 million for the year ended December 31, 2012 from $4.9 million for the year ended December 31, 2011. Other operating revenues for 2012 consisted of a $4.5 million loss on the sale of our natural gas assets including 100% of our Wind River Basin and Powder River Basin coalbed methane assets, and a non-operating working interest in our Piceance Basin development property. This loss was offset by $2.7 of income from gathering, compression and salt-water disposal fees received from third parties and $1.4 million from the sale of seismic data. Other operating revenues for 2011 primarily consisted of $2.9
million of income from gathering, compression and salt-water disposal fees received from third parties and $2.0 million in net gains realized from the sale and exchange of properties.
Lease Operating Expense. Lease operating expense increased to $3.71 per Boe for the year ended December 31, 2012 from $3.18 per Boe for the year ended December 31, 2011. The increase in lease operating expense is primarily related to oil producing properties in the Uinta and DJ Basins with inherently higher lifting costs per Boe compared to our natural gas properties.
Gathering,
Transportation and Processing Expense. GTP expense increased to $5.44 per Boe for the year ended December 31, 2012 from $5.25 per Boe for the year ended December 31, 2011. The increase for the year ended December 31, 2012 is primarily related to decreased drilling activity in the West Tavaputs area of the Uinta Basin due to lower gas prices. As a result of decreased drilling in 2012 and future years, we incurred a one-time charge of $4.4 million for deferred processing and gathering costs that we did not expect to recover in future years.
We entered into long-term firm transportation agreements for a portion of our natural gas production to guarantee capacity on major pipelines and reduce the risk and impact
related to possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation and processing agreements were for gas production in the Piceance and Uinta Basins. Included in GTP expense are $2.30 and $1.98 per Boe of firm transportation and gathering expense and $0.32 and $0.28 per Boe of firm processing expense from long-term contracts for the years ended December 31, 2012 and 2011, respectively. In connection with the 2012 Divestiture, our long-term firm transportation agreements related to this area were assumed by the purchaser.
Production Tax Expense. Total production taxes decreased to $25.5
million for the year ended December 31, 2012 from $37.5 million for the year ended December 31, 2011. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense decreased during the year ended December 31, 2012 primarily due to a 9.1% decrease in wellhead values of production, excluding hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 4.1% for the year ended December 31, 2012
and 5.5% for the year ended December 31, 2011.
Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The decrease in the overall production tax rate is consistent with our production decrease in states with higher production tax rates.
Exploration Expense. Exploration expense increased to $8.8 million for the year ended December 31,
2012 from $3.6 million for the year ended December 31, 2011. Exploration expense for the year ended December 31, 2012 consisted of $7.9 million for geological and geophysical seismic programs across several basins and $0.9 million for delay rentals across all basins. Exploration expense for the year ended December 31, 2011 consisted of $2.7 million for geological and geophysical seismic programs across several basins and $0.9 million for delay rentals across all basins.
Impairment, Dry Hole Costs and Abandonment Expense.
Our impairment, dry hole costs and abandonment expense decreased to $67.9 million for the year ended December 31, 2012 from $117.6 million for the year ended December 31, 2011. For the year ended December 31, 2012, impairment expense was $37.3 million, abandonment expense was $9.6 million and dry hole costs were $21.0 million. For the year ended December 31, 2011, impairment expense was
$100.3 million, abandonment expense was $3.9 million and dry hole costs were $13.4 million.
We evaluate the impairment of our proved oil and gas properties on a property-by-property basis annually or whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the property to fair value through a charge to impairment expense. For the year ended December 31, 2012, we did not record any impairment charges regarding proved oil and gas properties. For the year ended December 31, 2011, we recorded a $75.2 million impairment charge regarding proved
oil and gas properties within the coalbed methane fields of the Powder River Basin and a $7.6 million impairment charge
regarding proved oil and gas properties within the Wallace Creek field of the Wind River Basin as a result of declining natural gas prices.
Unproved oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop existing acreage. We recorded
non-cash impairment charges of $37.3 million and $17.5 million for the years ended December 31, 2012 and December 31, 2011, respectively, related to certain unproved oil and gas properties within various exploration and development projects primarily as a result of unfavorable natural gas exploratory results, unfavorable market conditions or discontinuing evaluation of the remaining acreage. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities.
We account for oil and gas exploration and production activities
using the successful efforts method of accounting under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well, and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. As of December 31,
2012, there were no exploratory well costs included in unproved oil and gas properties that had been capitalized for a period greater than one year since the completion of drilling.
Dry hole costs of $21.0 million for the year ended December 31, 2012 primarily relate to two unsuccessful exploratory natural gas wells in the Paradox Basin and one unsuccessful exploratory well in the Alberta Basin. Dry hole costs of $13.4 million for the year ended December 31, 2011 were associated with one uneconomic exploratory well in the McRae Gap prospect of the Wind River Basin and two unsuccessful exploratory wells within the northern
DJ Basin on acreage acquired prior to our 2011 DJ Basin acquisition.
Depreciation, Depletion and Amortization. DD&A increased to $326.8 million for the year ended December 31, 2012 compared with $288.4 million for the year ended December 31, 2011. The increase of $38.4 million was a result of a 10% increase in production for the year ended December 31, 2012 compared with the year ended December 31, 2011 coupled with an increase in the DD&A rate. The increase in production accounted for $14.4 million of additional DD&A expense, while the overall increase in the DD&A rate accounted for a $24.0 million increase in DD&A expense. The increase
in the DD&A rate during the year ended December 31, 2012 was due to an increase in the mix of oil projects, which have higher capital costs per reserve unit compared to natural gas projects, completed during the year ended December 31, 2012 compared to the year ended December 31, 2011.
Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the year ended December 31, 2012, the
relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $17.49 per Boe compared with $16.20 per Boe for the year ended December 31, 2011. Future depletion rates will be adjusted to reflect capital expenditures, changes in commodity prices, proved reserve changes and well performance.
General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $52.2 million for the year ended December 31, 2012 from $47.7 million for the year ended December 31, 2011. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the
table on page 49 for a reconciliation and explanation. This increase was primarily due to increased employee compensation and benefits expense, including severance costs incurred in 2012. On a per Boe basis, general and administrative expense, excluding non-cash stock based compensation, decreased to $2.66 in 2012 from $2.68 in 2011, due to the 10% increase in production from 2011 to 2012, offset by a 9% increase in general and administrative expenses in 2012.
Non-cash stock-based compensation expense was $16.4 million for the year ended December 31, 2012 compared with $19.0 million for the year ended December 31, 2011. Non-cash stock-based compensation expense for 2012 and 2011 related primarily to the vesting of our stock option awards, nonvested shares of common stock, and nonvested
performance-based equity granted to employees.
The components of non-cash stock-based compensation expense for 2012 and 2011 are shown in the following table:
Stock options and nonvested equity shares of common stock
$
15,435
$
18,100
Shares
issued for 401(k) plan
733
629
Shares issued for directors’ fees
276
307
Total
$
16,444
$
19,036
Interest
Expense. Interest expense increased to $95.5 million for the year ended December 31, 2012 from $58.6 million for the year ended December 31, 2011. The increase was primarily due to an increase in our weighted average outstanding debt, partially offset by lower average borrowing costs. Our weighted average outstanding debt increased to $1,175.4 million for the year ended December 31, 2012 from $587.4 million for the year ended December 31, 2011, primarily due to the issuance of our $400.0 million aggregate principal amount of 7.0% Senior Notes on March 12, 2012, a $100.8 million lease financing obligation entered into on July 23, 2012, and an increase
in the outstanding debt balance on our Amended Credit Facility, partially offset by the repayment of $147.2 million of Convertible Notes on March 20, 2012. Our weighted average interest rate for the year ended December 31, 2012 was 8.2% compared to 10.2% for the year ended December 31, 2011.
Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. We capitalized interest costs of $0.5 million and $1.4 million for the years ended December 31, 2012 and 2011, respectively. For the year ended December
31, 2012, we had fewer projects in progress as compared with the year ended December 31, 2011, which resulted in a lower amount of interest costs that were capitalized during the period.
Income Tax Expense. Income tax expense totaled $1.6 million and $17.7 million for the years ended December 31, 2012 and 2011, respectively, resulting in effective tax rates of 73.8% and 36.5%, respectively. Our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes. The effective tax rate increase from 2011 to
2012 was primarily the result of the decrease in operating income coupled with an increase in unfavorable book to tax differences affecting the tax rate calculation, which was primarily a decrease in tax deductible compensation related to incentive stock options. Additionally, a greater proportion of our operating revenue was attributable to higher tax rate jurisdictions, which increased the overall statutory tax rate. The effect of this rate increase on our prior year net deferred tax liability was included in income tax expense for the year ended December 31, 2012. At December 31, 2012, we had approximately $107.9 million of federal tax NOLs, which expire through 2032. We also had a federal alternative minimum tax credit carryforward of $1.3 million, which has no expiration date. We believe it is more likely than not that we will use these tax attributes to offset and
reduce current tax liabilities in future years. During the year ended December 31, 2012, due to a Colorado limitation on the ability to utilize state NOLs, we released $0.5 million of the previously recorded valuation allowance against state income tax credit carryforwards. The remaining $4.6 million deferred tax asset related to state income tax credit carryforwards continues to have a valuation allowance against it. We believe it is more likely than not that this deferred tax asset will not be realized.
Capital Resources and Liquidity
Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, including our Convertible Notes and senior notes, bank credit
facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital.
At December 31, 2013,
we had cash and cash equivalents of $54.6 million and a $115.0 million balance outstanding under our Amended Credit Facility. Our borrowing base is dependent on our proved reserves and hedge position and was, as of December 31, 2013, $625.0 million based on our June 30, 2013 proved reserves, adjusted for the sale of our West Tavaputs properties, and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit.
Net cash provided by operating activities was $265.3 million, $388.4 million and $479.3 million in 2013, 2012 and 2011, respectively. The changes in net cash provided by operating activities are discussed above in “Results of Operations”. The decrease in net cash provided by operating activities for the year ended December 31, 2013 compared to 2012 and 2011 was largely due to our asset sales, the 26% decrease in production volumes in 2013 and an increase in operating costs.
Commodity
Hedging Activities
Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.
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. We typically hedge a fixed price for natural gas at our sales points (NYMEX less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. At December 31, 2013, we had in place crude oil swaps covering portions of our 2014, 2015 and 2016 production, natural gas swaps covering portions of our 2014 and 2015 production and NGL swaps covering portions of our 2014 production.
In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of oil, natural gas and NGLs 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, 2013, the estimated fair value of all of our commodity derivative instruments was a net liability of $3.3 million, comprised of current and noncurrent assets and liabilities. We elected to discontinue cash flow hedge accounting effective January 1,
2012. We will reclassify the appropriate cash flow hedge amounts from AOCI, related to hedges designated as cash flow hedges prior to January 1, 2012, to gains and losses included in oil, natural gas and NGL production revenues as the hedged production quantities are produced.
The table below summarizes the realized and unrealized gains and losses that we recognized related to our oil, natural gas and NGL derivative instruments for the periods indicated:
Weighted
average fixed price includes propane and natural gasoline hedges.
(2)
Weighted average fixed price includes propane, normal butane and isobutane hedges.
By removing the price volatility from a portion of our oil related revenue for 2014, 2015 and 2016, natural gas related revenue for 2014 and 2015 and NGL related revenue for 2014, 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 us under 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
$
16.2
$
168.5
$
350.2
Drilling,
development, exploration and exploitation of oil and natural gas properties (1)
456.2
778.4
624.6
Geologic and geophysical costs
0.3
8.8
3.6
Furniture,
fixtures and equipment
1.3
6.9
8.9
Total (2)(3)
$
474.0
$
962.6
$
987.3
(1)
Includes
related gathering and facilities costs.
(2)
For the year ended December 31, 2013, 2012 and 2011, we received $306.3 million, $325.3 million and $2.0 million, respectively, of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.
(3)
Excludes
future reclamation liabilities of negative $6.6 million, $7.5 million and $12.1 million for the years ended December 31, 2013, 2012 and 2011, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $12.2 million, $39.3 million and $21.0 million for the years ended December 31, 2013, 2012 and 2011,
respectively.
Capital expenditures for acquisitions of proved and unproved properties and other real estate were $16.2 million for the year ended December 31, 2013. This was primarily related to acquisitions of unproved properties in the DJ, Powder River and Uinta Basins. The decrease in drilling, development, exploration and exploitation of oil and natural gas properties to $456.2 million for the year ended December 31, 2013 from $778.4 million for the year ended December 31,
2012 primarily related to a decrease in development drilling and completion activities within the Uinta and Piceance Basins.
Capital expenditures for acquisitions of proved and unproved properties and other real estate were $168.5 million for the year ended December 31, 2012. This was primarily related to our acquisitions of proved and unproved properties in the DJ, Powder River and Uinta Basins. The increase in drilling, development, exploration and exploitation of oil and natural gas properties to $778.4 million from $624.6 million for the year ended December 31, 2011 related
to an increase in development drilling and completion activities within the Uinta, Powder River and DJ Basins.
Our current estimated capital expenditure budget in 2014 is $500.0 million to $550.0 million, with all drilling activities targeting oil. The budget includes facilities costs and excludes acquisitions. We may adjust capital expenditures throughout the year as business conditions and operating results warrant. If we are successful in exploratory activities or overcoming legal and regulatory hurdles, we may consider increasing our capital budget. We believe that we have sufficient available liquidity through 2014 with available cash under the Amended Credit Facility, our hedge positions and cash flow from operations to fund our budgeted capital expenditures. Future cash flows
are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.
The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil and natural gas prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity generally by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow. We routinely
monitor and adjust our capital expenditures,
including acquisitions and divestitures, in response to changes in prices and other economic and market conditions, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside of our control.
Financing Activities
Amended
Credit Facility. Our Amended Credit Facility has a maturity date of October 31, 2016, and current commitments and borrowing base of $625.0 million. Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee is between 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility were 2.0% and 2.2% for the years ended December 31, 2013 and 2012, respectively. The maximum balance outstanding on the Amended Credit Facility in 2013 was $420.0 million and the average balance for the year ended December
31, 2013 was $183.8 million.
The borrowing base is required to be re-determined twice per year. Our borrowing base is dependent on our proved reserves and was, as of December 31, 2013, $625.0 million based on our June 30, 2013 proved reserves, adjusted for the sale of our West Tavaputs properties, hedge position and senior debt outstanding. Our borrowing capacity is reduced by a $26.0 million letter of credit. Future semi-annual borrowing bases under our Amended Credit Facility will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the
Company.
The Amended Credit Facility is secured by oil and natural gas properties representing at least 80% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since origination. As of December 31, 2013, we had $115.0 million outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued
under the Amended Credit Facility, which reduced the borrowing capacity of the Amended Credit Facility to $484.0 million as of December 31, 2013.
9.875% Senior Notes Due 2016. On July 15, 2013, we redeemed the entire outstanding $250.0 million principal amount of 9.875% Senior Notes for a redemption price of 104.938% of the principal amount of the notes, or $262.3 million. Unamortized debt discount and deferred financing costs related to the notes resulted in a loss upon settlement of $21.5 million for the year ended December 31, 2013.
5%
Convertible Senior Notes Due 2028. On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to us and were redeemed by us at par. We settled the notes in cash. After the redemption, $25.3 million aggregate principal amount of the Convertible Notes was outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by us. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior unsecured indebtedness, are senior in right of payment to all of our future subordinated indebtedness, and are effectively subordinated
to all of our secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of our subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.
The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require us to purchase all or a portion of their Convertible Notes for cash
on each of March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. We have the right at any time with at least 30 days’ notice to call the Convertible Notes and redeem at par.
7.625% Senior Notes Due 2019. On September 27, 2011, we issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1
beginning April 1, 2012. The 7.625% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell
assets
and that prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. The 7.625% Senior Notes are redeemable at our option beginning on and after October 1, 2015 at a redemption price of 103.813% of the principal amount of the notes.
7.0% Senior Notes Due 2022. On March 12, 2012, we issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year beginning October 15, 2012. The 7.0% Senior Notes are senior
unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. The 7.0% Senior Notes are redeemable at our option beginning on and after October 15, 2017 at a redemption price of 103.5% of
the principal amount of the notes.
Lease Financing Obligation Due 2020. On July 23, 2012, we entered into a lease financing arrangement with Bank of America Leasing & Capital, LLC as the lead bank (the “Lease Financing Obligation”) whereby we received $100.8 million through the sale and subsequent leaseback of existing compressors and related facilities owned by us. The Lease Financing Obligation expires on August 10, 2020, and we have 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 where we may purchase the equipment for $36.6 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%. As part of the purchase and sale agreement for our West Tavaputs natural gas properties in the Uinta Basin, the purchaser assumed approximately 51% of the Lease Financing Obligation, including the buy out option, leaving $43.3 million outstanding principal as of December 31, 2013.
The
recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure and on financing terms currently available to the Company.
(2)
The aggregate estimated fair value of the 9.875% Senior Notes was $271.9 million as of December 31, 2012 based on reported market trades of these instruments. We redeemed these notes in full on July 15, 2013.
(3)
The
aggregate estimated fair value of the Convertible Notes was approximately $25.1 million and $25.3 million as of December 31, 2013 and 2012, respectively, based on reported market trades of these instruments.
(4)
We have the right at any time with at least 30 days’ notice to call the Convertible Notes, and the holders have the right to require us to purchase the notes on each of March 20, 2015, March 20,
2018 and March 20, 2023.
(5)
The aggregate estimated fair value of the 7.625% Senior Notes was approximately $430.2 million and $435.0 million as of December 31, 2013 and 2012, respectively, based on reported market trades of these instruments.
(6)
The
aggregate estimated fair value of the 7.0% Senior Notes was approximately $417.0 million and $413.8 million as of December 31, 2013 and 2012, respectively, based on reported market trades of these instruments.
(7)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $41.7 million and $97.7 million as of December 31,
2013 and 2012, respectively. Because 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.
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 7.625% Senior Notes and 7.0% 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 Convertible Notes, the 7.625% Senior Notes or the 7.0% 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, 2013 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)
$
553
$
553
$
115,553
$
553
$
182
$
—
$
117,394
7.625%
Senior Notes (2)
30,500
30,500
30,500
30,500
30,500
422,875
575,375
7.0%
Senior Notes (3)
28,000
28,000
28,000
28,000
28,000
506,167
646,167
Convertible
Notes (4)
1,267
25,622
—
—
—
—
26,889
Lease
Financing Obligation (5)
5,942
5,942
5,942
5,942
5,942
9,901
39,611
Purchase
commitments (6)(7)
—
1,695
—
—
—
—
1,695
Drilling
rig commitments (7)(8)
2,952
—
—
—
—
—
2,952
Office
and office equipment leases and other (9)(10)
4,655
10,014
2,678
2,517
2,525
633
23,022
Firm
transportation and processing agreements (7)(11)
36,905
36,717
35,466
33,085
33,521
63,813
239,507
Asset
retirement obligations (12)
3,805
693
882
663
696
36,266
43,005
Derivative
liability (13)
5,988
12
—
—
—
—
6,000
Total
$
120,567
$
139,748
$
219,021
$
101,260
$
101,366
$
1,039,655
$
1,721,617
(1)
Included
in notes payable is the outstanding principal amount under our Amended Credit Facility due October 31, 2016. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. Also included in notes payable is a $26.0 million letter of credit that accrues interest 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.
(2)
On
September 27, 2011, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes. We are obligated to make annual interest payments through maturity in 2019 equal to $30.5 million.
(3)
On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make annual interest payments through maturity in 2022 equal to $28.0 million.
(4)
On March 12,
2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012 approximately 85% of the outstanding Convertible Notes, representing $147.2 million of the then outstanding principal amount, were put to us. We settled the notes in cash and recognized a gain on extinguishment of $1.6 million after completing a fair value analysis of the consideration transferred to holders of the Convertible Notes. After the redemption in March 2012, $25.3 million principal amount of the Convertible Notes is currently outstanding. We are obligated to make semi-annual interest payments on the Convertible Notes until either we call the remaining Convertible Notes or the holders put the Convertible Notes to us, which is expected to occur by 2015.
(5)
The
Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments.
(6)
We have one take-or-pay carbon dioxide purchasing agreement that expires in December 2015. The agreement imposes a minimum volume commitment to purchase CO2 at a contracted price. The contract provides CO2 used in fracture stimulation operations. If we do not take delivery of the minimum volume required, we are obligated to pay for the deficiency. As of December 31, 2013, $1.7 million of the future commitment was due by December 31,
2015.
(7)
The values in the table represent the gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest and net revenue interest, which will vary from property to property.
(8)
We currently have one drilling rig under contract. This contract
expires in 2014. This contract may be terminated prior to the expiration date but we would be required to pay a penalty computed at $3.0 million as of December 31, 2013. All other
rigs currently performing work for us are on a well-by-well basis and, therefore, can be released without penalty at the conclusion of drilling on the current well. These latter types of drilling obligations have not been included in the table above.
(9)
The
lease for our principal offices in Denver extends through March 2019.
(10)
We have entered into a drilling carry agreement in the amount of $8.5 million related to acreage in the Powder River Basin. As of December 31, 2013, we have satisfied $1.6 million of this agreement. If we do not satisfy the carry amount by October 1, 2015, the remaining balance must be remitted.
(11)
We
have entered into contracts that provide firm processing rights and firm transportation capacity on pipeline systems. The remaining terms on these contracts range from 2 to 8 years and require us to pay transportation demand and processing charges regardless of the amount of gas we deliver to the processing facility or pipeline.
(12)
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.
(13)
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, 2013. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See “Critical Accounting Policies and Estimates” in Part II, Item 7 of this Annual Report on Form 10-K for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.
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 and increases the cost to conduct our operations. Areas in which we operate are subject to federal, state, local and tribal regulations. All these jurisdictions have imposed additional and more restrictive regulations recently and there are initiatives underway to implement additional regulations and prohibitions on oil and gas activities. New rules may further impact the ability and extend the time necessary to obtain drilling permits and other required approvals, which creates substantial uncertainty about our production
and capital expenditure targets.
Federal. Federal leases make up approximately 32% of our leaseholds. At the federal level, the policies of the current administration and the Department of the Interior have resulted in a more restrictive regulatory environment for oil and gas activities on public lands. The Secretary of Interior has issued policy directives that require additional analysis prior to leasing federal lands. These policies are directed at reducing controversy and improving predictability of the leasing process. We believe that until these policies are implemented and the requisite analyses are completed, the rate of federal leasing will decrease. The BLM and the U.S. Forest Service also have withdrawn parcels from planned lease sales in areas near our operations. A lawsuit seeks review of federal
resource management plans prepared by the BLM for areas of Utah, including areas in which we operate. If this challenge is successful, it could impact our ability to operate and to obtain additional leases in the area. Additional litigation seeking to halt our and other companies’ exploration and development activities throughout the Rockies can be expected. Proposals to cause expiration of undeveloped leases, to further limit funding for processing of federal drilling permits and to eliminate categorical exclusions for oil and gas activities have been reintroduced.
State. We also are experiencing increased attempts to more strictly regulate oil and gas activities at the state level. New rules and policies have been imposed by the COGCC requiring disclosure of chemicals used in hydraulic fracturing, ground water monitoring and setbacks from occupied structures
and existing wells. Legislation has been introduced in other states that is similar to the rules adopted in Colorado. Several states also have proposed severance tax increases.
Local. Counties and municipalities regulate oil and gas activities primarily through local land use rules. Most counties and municipalities where we operate require special use permits for activities that previously were regulated by the states, adding new requirements and delays over previous operations. We expect additional attempts to regulate activities related to oil and gas operations by local governments, including potential moratoria or bans on hydraulic fracturing.
Tribal. We have experienced delays in obtaining permits to drill wells and access and rights of
way agreements on tribal property, including our Lake Canyon and Black Tail Ridge projects. The failure to obtain permits has led us to declare a force majeure event in order to protect our rights under our Black Tail Ridge exploration and development agreement. Because of the current staffing of the permitting authorities, we believe that delays in obtaining permits will continue for the foreseeable future, which will delay our ability to drill wells in these areas.
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. In reaction to the increased scrutiny of this technique, moratoria have been imposed in certain localities where we do not have operations and legislation proposed at federal, state and local levels. Although it is not possible at this time to predict the final outcome of the proposed legislation 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, if the use of hydraulic
fracturing is limited or prohibited, would lead to our inability to access, develop and record natural gas and oil reserves in the future.
Air Quality Regulation. The EPA regulates the level of ozone in ambient air and is proposing to lower the allowed level of ozone. Because of certain climate processes, most of the Rockies, where we operate, have higher levels of ozone. As a result of these existing and possibly more stringent standards, we may not be able to obtain permits necessary to construct and operate new facilities, or, if we obtain the permits, the added costs to comply with the requirements could substantially increase our operating expenses, which would reduce our profits or make certain operations uneconomic. In addition, at the state level, air quality regulations in Colorado may become more stringent and in all states permits for air emissions
may take longer to obtain, which would delay our ability to produce.
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 accumulated leases, especially federal leases which make up approximately 32% of our leaseholds. For example, until we obtain regulatory approvals to commence activities in our Cottonwood Gulch area, we are unable to record additional reserves in this area. We currently
are unable to estimate the total magnitude of these potential impacts.
Declining Commodity Prices. In 2012, natural gas prices were the lowest in over 10 years due to oversupply and low demand as a result of a mild winter. Certain NGL prices (ethane and propane) also were negatively impacted by the low natural gas prices and oversupply. In 2013, natural gas prices improved slightly but the U.S continues to produce record volumes. Oil prices remained relatively strong due to macroeconomic factors and geopolitical concerns. If natural gas prices remain low for an extended period of time, it will affect the timing of when we would drill in our Piceance properties, which could affect future growth rates and cause certain proved undeveloped reserves to be removed from our proved reserves estimates if they will not be drilled within five years. If oil prices decline
materially from current levels, drilling in our DJ and Uinta Oil 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. We currently have hedged approximately 65% of our expected 2014 production and 20% of our expected 2015 production at price levels that provide some economic certainty to our capital investments. Continued low commodity prices make it more challenging to achieve high hedged prices levels. Low commodity prices also increase the likelihood of impairments.
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.
60
Oil and Gas Properties
Our
oil, natural gas and NGL exploration, development 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 property has proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed 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. 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 gas and oil 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 depletion rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. 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. 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 on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. During the year ended December 31, 2013, we recorded impairment charges of $17.1
million related to certain unproved oil and gas properties within exploration projects primarily as a result of no future plans to evaluate the remaining acreage and an estimated market value below our carrying value. In addition, we recorded impairment charges of $2.5 million related to our West Tavaputs unproved properties based upon an analysis of the carrying value of the related properties relative to their estimated fair values. We sold these assets in December 2013. During the year ended December 31, 2012, we recorded impairment charges of $37.3 million of the carrying value of unevaluated oil and gas properties related to certain unproved oil and gas properties within exploration projects primarily as a result of unfavorable natural gas exploratory results, unfavorable market conditions or no future plans to evaluate the
remaining acreage. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities. We continue to review our acreage position and future drilling plans based on the current price environment. If our attempts to market interests in certain of our properties to industry partners are unsuccessful, we may record additional leasehold impairments and abandonments in exploration projects.
We review our proved oil and natural gas properties for impairment on an annual basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted future cash flows to the carrying amount of the oil and gas
properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, 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 associated with realizing the projected cash flows. During the year ended December 31, 2013, we recorded impairment charges of $207.0 million related to our West Tavaputs properties based upon an analysis of the carrying value of the
related properties relative to their estimated fair values. We sold these assets in December 2013. We did not record an impairment charge regarding proved oil and gas properties for the year ended December 31, 2012.
61
The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in anticipation of finding a gas and oil field that will be the focus of future development drilling activity. If initial exploratory wells are unsuccessful, they are expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.
Our
investment in 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 recognition of an asset retirement obligation (“ARO”) requires that management make numerous estimates, assumptions and judgments regarding such factors as amounts, future advances in technology, timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the
liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors and changes to our credit-adjusted risk-free rate as market conditions warrant. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our DD&A expense in future periods.
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 is converted to barrel of oil equivalents, Boe, at the standard rate of six Mcf to one barrel. 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, 2013.
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
We record revenues from the sales of oil, natural gas and NGLs in the month that delivery to the purchaser has occurred and title has transferred.
We receive payment from one to three months after delivery. At the end of each month, we estimate
62
the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically, any differences have been insignificant.
Derivative Instruments and Hedging Activities
We use derivative financial instruments to achieve a more predictable cash flow from our oil, natural gas and NGLs 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.
Effective January 1, 2012, we elected to discontinue hedge accounting prospectively. Consequently, as of January 1, 2012, we no longer designate any hedges as cash flow hedges and we elected to de-designate all commodity hedge instruments that were previously designated as cash flow hedges as of December 31, 2011. The election to de-designate commodity hedges did not impact our reported cash flows, did not affect the economic substance of these transactions and changes only how these transactions are reported in the Consolidated Financial Statements. As a result of discontinuing hedge accounting effective January
1, 2012, the mark-to-market value of all commodity hedge instruments within accumulated other comprehensive income (“AOCI”) at December 31, 2011 was frozen in AOCI as of the de-designation date and will be reclassified into earnings in future periods as the original hedged transactions occur. All cash flow hedged transactions are scheduled to be completed by December 31, 2014.
The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Before discontinuing cash flow hedge accounting effective January 1, 2012, we were required to formally document, at the inception of a hedge, the
hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.
For derivative instruments that were designated as cash flow hedges, changes in fair value, to the extent the hedge was effective, were recognized in AOCI until the hedged item was recognized in earnings. Hedge effectiveness was assessed quarterly based on total changes in the derivatives’ fair value. Any ineffective portion of the derivative instrument’s change in fair value was recognized immediately in earnings.
Currently,
our financial derivative instruments are marked to market with the resulting changes in fair value recorded in earnings. As a result of our election to discontinue cash flow hedge accounting effective January 1, 2012, we reclassified the commodity derivative gain (loss) line item within the Consolidated Statements of Operations from operating and other revenues to other income and expenses, due to the change in the composition of the commodity derivative gain (loss) line item, to include prospective fair value changes of hedge instruments.
The estimates of the fair values of our derivative instruments require substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, 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 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 establish deferred tax asset valuation allowances in a future period.
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
63
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,
2013.
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.
Stock-Based Compensation
We recognize compensation expense for all share-based payment
awards made to employees and directors. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period. Judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies. The Black-Scholes option-pricing model uses assumptions regarding expected volatility of our common stock, the risk-free interest rates, expected term of the awards and other valuation inputs, which are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized. The Monte Carlo simulation method uses assumptions regarding random projections and must be repeated numerous times to achieve a probable assessment.
Any change in inputs or number of inputs to this calculation could impact the valuation and thus the stock-based compensation expense recognized.
We recorded non-cash stock-based compensation expense of $15.6 million, $16.4 million and $19.4 million for the years ended December 31, 2013, 2012 and 2011, respectively, for option grants, option modifications, nonvested equity shares of common stock, nonvested equity shares of common stock units, and nonvested performance-based equity shares of common stock.
New
Accounting Pronouncements
In January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-1, Balance Sheet: Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which amended FASB Accounting Standards Codification (“ASC”) Topic 210, Balance Sheet. The main objective in developing this update was to address implementation issues about the scope of ASU 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities. The amendments clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase
agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This provision is effective for fiscal years beginning on or after January 1, 2013. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.
In February 2013, the FASB issued ASU 2013-2, Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which amended ASC Topic 220, Comprehensive Income. The objective of this update was to improve the reporting of reclassifications out of accumulated
other comprehensive income. The amendment did not change the requirements for reporting net income or other comprehensive income in financial statements. However, the amendment required an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This provision is effective for
interim and annual periods beginning after December 15, 2012. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.
In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or
64
a tax credit carryforward
exists. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this standard will not have an impact on the Company’s 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 in 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, 2013, our annual revenues would have decreased by approximately $0.4 million for each $1.00 per barrel decrease in crude oil prices, $0.6 million for each $0.10 decrease per MMBtu in natural
gas prices and $1.7 million for each $1.00 per barrel decrease in NGL prices. We are more susceptible to proved and unproved property impairments due to the current commodity price environment.
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.
As
of January 24, 2014, 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 2014
For
the year 2015
For the year 2016
Oil (Bbls)
3,211,400
1,348,700
91,000
Natural Gas (MMbtu)
24,335,000
3,650,000
—
Natural
Gas Liquids (Bbls)
319,048
—
—
Interest Rate Risks
At December 31, 2013, we had $115.0 million outstanding
under our Amended Credit Facility, which bears interest at floating rates. The average annual interest rate incurred on this debt for the year ended December 31, 2013 was 2.0%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the year ended December 31, 2013 would have resulted in an estimated $1.8 million increase in interest expense assuming a similar average debt level to the year ended December 31, 2013. The average annual interest rate incurred on this debt for the year ended December 31, 2012 was 2.2%. A 1.0% increase in each of the average LIBOR rate and
federal funds rate for the year ended December 31, 2012 would have resulted in an estimated $1.2 million increase in interest expense assuming a similar average debt level to the year ended December 31, 2012. We also had $25.3 million principal amount of Convertible Notes (with a fixed cash interest rate of 5%), $400.0 million principal amount of 7.625% Senior Notes, $400.0 million principal amount of 7.0% Senior Notes and $43.3 million principal amount of 3.3% Lease Financing Obligation outstanding at December 31, 2013.
Item
8.
Financial Statements and Supplementary Data.
The information required by this item is included below in “Item 15. Exhibits, Financial Statement Schedules”.
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, 2013, we carried out an evaluation, under
the supervision and with the participation of management, including the Chief Executive Officer and Chief 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 Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of December 31, 2013.
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 the Chief
Executive Officer and Chief 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 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 (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment we have concluded that, as of December 31, 2013, 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 has been no change in our internal control over financial reporting during the fourth fiscal quarter of 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the Board of Directors and Stockholders of
Bill Barrett Corporation
Denver, Colorado
We have audited the internal control over financial reporting of Bill Barrett Corporation and subsidiaries (the “Company”) as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our
opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2013 of the Company and our report dated February 20,
2014 expressed an unqualified opinion on those financial statements.
Directors, Executive Officers and Corporate Governance.
The information required by
this item will be included in an amendment to this Form 10-K or in the “Directors and Executive Officers” section, the “Section 16(a) Beneficial Ownership Reporting Compliance” section, the “Code of Business Conduct and Ethics” section and the “Corporate Governance” section of the proxy statement for the 2014 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2013, and is incorporated by reference to this report.
Item
11.
Executive Compensation.
The information required by this item will be included in an amendment to this Form 10-K or in the “Executive Compensation” section and the “Director Compensation” section of the proxy statement for the 2014 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2013, and is incorporated by reference to this report.
Item
12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the “Beneficial Owners of Securities” section of the proxy statement for the 2014 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2013, and is incorporated by reference to this report.
Equity Compensation Plan Information
The
following table provides aggregate information presented as of December 31, 2013 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
Number of Securities
Remaining
Available
for Future Issuance
(Excluding Securities
Reflected in Column (a))
Equity compensation plans approved by shareholders
1,748,696
$
32.66
(1)
2,091,811
Equity
compensation plans not approved by shareholders
—
—
Total
1,748,696
$
32.66
2,091,811
(1)
The
weighted average exercise price relates to the 1,748,696 outstanding options included in column (a). Column (a) does not include 1,340,060 nonvested shares of common stock (restricted stock), or 55,778 nonvested shares of common stock units (restricted stock units) granted under our stockholder-approved equity compensation plans.
Item 13.
Certain Relationships and Related Transactions and Director Independence.
The information required by this item
will be included in an amendment to this Form 10-K or in the “Approval of Related Party Transactions” section and the “Corporate Governance” section of the proxy statement for the 2014 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2013, and is incorporated by reference to this report.
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Item
14.
Principal Accounting Fees and Services.
The information required by this item will be included in an amendment to this Form 10-K or in the “Fees to Independent Auditors” section of the proxy statement for the 2014 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2013, and is incorporated by reference to this report.
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PART
IV
Item 15.
Exhibits, Financial Statement Schedules.
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules.
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Stockholders' Equity for the years ended December 31, 2013, 2012 and 2011
83
Notes
to Consolidated Financial Statements
84
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.
(a)(3) Exhibits.
Exhibit
Number
Description
of Exhibits
2.1
Purchase and Sale Agreement dated October 31, 2012 between Bill Barrett Corporation and Bill Barrett CBM Corporation, as Sellers, Encore Energy Partners Operating, LLC, as Buyer, and Vanguard Natural Resources LLC as Parent Guarantor. [Incorporated by reference to Exhibit 2 of our Current Report on Form 8-K filed with the Commission on November 5, 2012.]
2.2
Purchase
and Sale Agreement, dated October 22, 2013, among Bill Barrett Corporation, Enervest Energy Institutional Fund XIII-A, L.P., Enervest Energy Institutional Fund XIII-WIB, L.P. and Enervest Energy Institutional Fund XIII-WIC, L.P. [Incorporated by reference to Exhibit 2 of our Current Report on Form 8-K filed with the Commission on October 25, 2013.]
2.3
Amendment to Purchase and Sale Agreement, dated December
10, 2013, among Bill Barrett Corporation, Enervest Energy Institutional Fund XIII-A, L.P., Enervest Energy Institutional Fund XIII-WIB, L.P. and Enervest Energy Institutional Fund XIII-WIC, L.P. [Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed with the Commission on December 11, 2013.]
Specimen
Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
Indenture, dated July 8, 2009, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on
July 8, 2009.]
First
Supplemental Indenture, dated March 12, 2008, by and between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 5% Convertible Senior Notes due 2028). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.3(a)
Stockholders’ Agreement,
dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.3(b)
Second Supplemental Indenture,
dated July 8, 2009, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM LLC, Circle B Land Company LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K with the Commission on July 8, 2009.]
4.3(c)
Third Supplemental Indenture,
dated September 27, 2011, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM LLC, Circle B Land Company LLC, GB Acquisition Corporation, Elk Production, LLC, Aurora Gathering, LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of 7.625% Senior Notes due 2019). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K with the Commission on September 27, 2011.]
Form
of Rights Agreement concerning Shareholder Rights Plan, which includes, as Exhibit A thereto, the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and, as Exhibit B thereto, the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.5
Form
of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.6
Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the
Commission on December 20, 2004.]
4.7
Amendment No. 1 to Rights Agreement, dated as of March 18, 2013, between Bill Barrett Corporation and Computershare Shareowner Services LLC. [Incorporated by reference to Exhibit 4.5 to Amendment No. 2 to our Registration Statement on Form 8-A filed with the Commission on March
18, 2013.]
10.1(a)
Third Amended and Restated Credit Agreement, dated as of March 16, 2010, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2010.]
10.1(b)
First
Amendment to Third Amended and Restated Credit Agreement dated as of October 18, 2011 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 18, 2011.]
71
Exhibit
Number
Description
of Exhibits
10.2
Stock Purchase Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 10.2 to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.3(a)*
Form
of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of the directors and certain executive officers of the Company. [Incorporated by reference to Exhibit 10.10(a) to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.3(b)*
Schedule
of officers and directors party to Indemnification Agreements dated April 15, 2004 with Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.10(b) to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.4*
Amended and Restated 2002 Stock Option
Plan. [Incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.5(a)*
Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to Amendment No. 4 to our
Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.5(b)*
Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b) to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554)
filed with the Commission on October 13, 2004.]
Form
of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.8
Form of Management Rights Agreement between Bill Barrett
Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.9
Regulatory Side Letter, dated March 28, 2002, between J.P. Morgan Partners (BHCA), L.P. and Bill Barrett Corporation.
[Incorporated by reference to Exhibit 10.17 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.10*
Form of Change in Control Severance Protection Agreement, revised as of November 16, 2006, for named executive officers. [Incorporated
by reference to Exhibit 10.10 to our Annual Report on Form 10-K for the year ended December 31, 2006.]
10.11*
2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.12*
Revised
Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
72
Exhibit
Number
Description
of Exhibits
10.13*
Form of Restricted Common Stock Award Agreement for 2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
10.14(a)*
Form of Performance Vesting Restricted Stock Agreement for 2004
Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
10.14(b)*
Form of Performance Vesting Restricted Stock Agreement for 2004 Stock Incentive Plan (2009 Temporary Supplemental Grant). [Incorporated by reference to Exhibit 10.14(b) to our Quarterly Report on Form 10-Q for the three months ended March
31, 2009.]
Form
of Stock Option Agreement for 2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the year ended December 31, 2008.]
Form
of Restricted Common Stock Unit Award for 2012 Equity Incentive Plan. [Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on July 2, 2012.]
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 Board of Directors and Stockholders of
Bill Barrett Corporation
Denver, Colorado
We
have audited the accompanying consolidated balance sheets of Bill Barrett Corporation and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Bill Barrett Corporation and subsidiaries as of December 31, 2013 and 2012,
and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with 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), the Company's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2014 expressed an unqualified opinion
on the Company's internal control over financial reporting.
Accounts
receivable, net of allowance for doubtful accounts
97,586
112,011
Derivative assets
173
29,980
Prepayments and other current assets
4,893
6,903
Total
current assets
157,247
228,339
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties
2,863,923
3,331,267
Unproved
oil and gas properties, excluded from amortization
296,599
457,207
Furniture, equipment and other
41,726
45,636
3,202,248
3,834,110
Accumulated
depreciation, depletion, amortization and impairment
(999,752
)
(1,222,773
)
Total property and equipment, net
2,202,496
2,611,337
Deferred financing
costs and other noncurrent assets
21,770
29,773
Total
$
2,381,513
$
2,869,449
Liabilities
and Stockholders’ Equity:
Current liabilities:
Accounts payable and accrued liabilities
$
115,928
$
125,017
Amounts
payable to oil and gas property owners
26,778
19,663
Production taxes payable
39,235
45,624
Derivative liabilities
5,988
—
Deferred
income taxes
199
13,752
Current portion of long-term debt
4,591
9,077
Total current liabilities
192,719
213,133
Long-term
debt
979,082
1,156,654
Asset retirement obligations
39,200
46,050
Deferred income taxes
161,326
266,364
Derivatives
and other noncurrent liabilities
3,468
4,473
Stockholders’ equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 49,152,448 and 48,150,475 shares issued and outstanding at December 31, 2013 and 2012,
respectively, with 1,340,060 and 870,794 shares subject to restrictions, respectively
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 the expected cash settlement of the Company’s 5% Convertible Senior Notes due 2028 (“Convertible Notes”) in computing diluted earnings per share, 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.
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 included 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 within cash flows from investing activities in the Consolidated Statements of Cash Flows when incurred. The costs of development wells are capitalized whether proved reserves are added
or not. Oil and gas lease acquisition costs are also capitalized.
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. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. 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 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, on a first-in, first-out basis.
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
$
296,599
$
457,207
Accumulated
depreciation, depletion, amortization and impairment
(976,339
)
(1,203,495
)
Total oil and gas properties, net
$
2,184,183
$
2,584,979
Net
changes in capitalized exploratory well costs for the years ended December 31, 2013, 2012 and 2011, respectively, are reflected in the following table:
Additions to capitalized exploratory well costs pending the determination of
proved reserves
—
—
110
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
—
—
(6,179
)
Exploratory
well costs charged to dry hole costs and abandonment expense
—
—
(2,972
)
End of period
$
—
$
—
$
—
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.
The Company reviews proved oil and gas properties on a field-by-field basis for
impairment on an annual basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying value of a property exceeds the undiscounted future cash flows, the Company will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, 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.
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:
Non-cash impairment of proved oil and gas properties
$
206,953
(1)
$
—
$
82,814
(2)
Non-cash
impairment of unproved oil and gas properties
19,598
(3)
37,348
(4)
17,464
(5)
Dry hole costs
1,124
21,012
13,391
Abandonment
expense
10,723
9,509
3,930
Total non-cash impairment, dry hole costs and abandonment expense
$
238,398
$
67,869
$
117,599
(1)
Non-cash
impairment of proved oil and gas properties for the year ended December 31, 2013 related to our West Tavaputs properties based upon an analysis of the carrying value of the related properties relative to their estimated fair values. These assets were sold in December 2013.
(2)
Non-cash impairment of proved oil and gas properties for the year ended December 31, 2011 related to properties within the Powder River and Wind River Basins. The impairment was the result of an analysis of the carrying value of the related properties relative to their estimated fair
values.
(3)
Non-cash impairment of unproved oil and gas properties for the year ended December 31, 2013 was comprised of $17.1 million related to certain unproved oil and gas properties within exploration projects primarily as a result of no future plans to evaluate the remaining acreage and an estimated market value below our carrying value and $2.5 million related to our West Tavaputs properties based upon an analysis of the carrying value of the related properties relative to their estimated fair values. These assets were sold in December 2013.
(4)
Non-cash
impairment of unproved oil and gas properties for the year ended December 31, 2012 related to certain unproved oil and gas properties within exploration projects primarily as a result of unfavorable natural gas exploratory results, unfavorable market conditions or no future plans to evaluate the remaining acreage.
(5)
Non-cash impairment of unproved oil and gas properties for the year ended December 31, 2011 related to certain unproved oil and gas properties within exploration projects primarily as a result of no future plans to evaluate the remaining acreage
and an estimated market value below our carrying value.
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 is converted to barrel of oil equivalents, Boe, at the standard rate of six Mcf to one barrel. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration by this calculation.
Accounts Payable and Accrued Liabilities. Accounts payable and accrued liabilities are comprised of the following:
Accrued
lease operating, gathering, transportation and processing expenses
17,317
16,862
Accrued general and administrative expenses
14,605
13,054
Trade
payables and other
29,256
53,007
Total accounts payable and accrued liabilities
$
115,928
$
125,017
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.
Revenue Recognition. The Company records revenues from the sales of oil, natural gas and NGLs when delivery to the purchaser has occurred. The Company uses the sales method to account for gas and NGL imbalances. Under this method, revenue is 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 considered in the Company’s proved oil, gas and NGL reserves. Imbalances at December 31, 2013 and 2012 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.
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.
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, in-the-money outstanding stock options to purchase the
Company’s common stock and shares into which the Convertible Notes are convertible. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the year ended December 31, 2013.
In satisfaction of its obligation upon conversion of the Convertible Notes, the Company may elect to deliver, at its option, cash, shares of its common stock or a combination of cash and shares of its common stock. As of December 31, 2013, the Company expected to settle the remaining Convertible Notes in cash.
Therefore, the treasury stock method was used to measure the potentially dilutive impact of shares associated with that remaining conversion feature. The Company has the right at any time with at least 30 days’ notice to call the Convertible Notes and the holders have the right to require the Company to purchase the notes on March 20, 2015, March 20, 2018 and March 20, 2023. The Convertible Notes have not been dilutive since their issuance in March 2008 and, therefore, did not impact the diluted net income (loss) per common share calculation for the years ended December 31,
2012 and 2011. The diluted net income (loss) per common share excludes the anti-dilutive effect of 3,162,436 and 115,215 shares of stock options and nonvested equity shares of common stock for the years ended December 31, 2012 and 2011, respectively.
The following table sets forth the calculation of basic and diluted net income (loss) per share:
Basic
weighted-average common shares outstanding in period
47,497
47,195
46,536
Add dilutive effects of stock options and nonvested equity shares of common stock
—
159
701
Diluted
weighted-average common shares outstanding in period
47,497
47,354
47,237
Basic net income (loss) per common share
$
(4.06
)
$
0.01
$
0.66
Diluted
net income (loss) per common share
$
(4.06
)
$
0.01
$
0.65
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 January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-1, Balance Sheet:
Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which amended FASB Accounting Standards Codification (“ASC”) Topic 210, Balance Sheet. The main objective in developing this update was to address implementation issues about the scope of ASU 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities. The amendments clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This provision
is effective for fiscal years beginning on or after January 1, 2013. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.
In February 2013, the FASB issued ASU 2013-2, Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which amended ASC Topic 220, Comprehensive Income. The objective of this update was to improve the reporting of reclassifications out of accumulated other comprehensive income. The amendment did not change the requirements for reporting net income or other comprehensive income in financial statements. However, the amendment required an entity to provide information about the amounts
reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This provision is effective for interim and annual periods beginning after December 15, 2012. Adoption of this update did not have a material impact on the
Company’s disclosures or financial statements.
In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.
3.
Supplemental Disclosures of Cash Flow Information
Supplemental
disclosures of non-cash investing and financing activities:
Current liabilities
75,340
49,598
66,257
Net
increase (decrease) in asset retirement obligations
(6,996
)
(25,236
)
13,185
Treasury stock acquired for employee stock option exercises
—
—
592
Retirement
of treasury stock
1,778
2,513
4,436
4. Divestitures
On December 10, 2013, the Company completed the sale
of its West Tavaputs natural gas assets in the Uinta Basin (the “West Tavaputs Divestiture”). The Company received $309.4 million in cash proceeds, after initial closing adjustments. The divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized during 2014. The Company recognized an impairment loss of $209.5 million in the year ended December 31, 2013 related to these assets. The carrying amounts by major asset class within the disposal group are summarized below:
Accumulated depreciation, depletion, amortization and impairment
(706,810
)
Other Assets
1,533
Total
assets
$
368,020
Liabilities
Asset retirement obligation
$
13,471
Lease financing obligation
45,190
Total
liabilities
$
58,661
Net assets
$
309,359
On December 31, 2012, the Company completed the sale of natural gas assets
including 100% of its Wind River Basin, 100% of the Powder River Basin coalbed methane assets, and a non-operating working interest in its Gibson Gulch-Piceance Basin development property (the “2012 Divestiture”). The Company received $325.3 million in cash proceeds and recognized a $4.5 million pre-tax loss included in other operating revenues for the year ended December 31, 2012. Due to final post-closing adjustments, the Company recognized an additional $3.1 million pre-tax loss included in other operating revenues
for the year ended December 31, 2013.
5. Long-Term Debt
The Company’s outstanding debt is summarized below:
The
recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure and on financing terms currently available to the Company.
(2)
The aggregate estimated fair value of the 9.875% Senior Notes was $271.9 million as of December 31, 2012 based on reported market trades of these instruments. The 9.875% Senior Notes were redeemed in full on July
15, 2013.
(3)
The aggregate estimated fair value of the Convertible Notes was approximately $25.1 million and $25.3 million as of December 31, 2013 and 2012, respectively, based on reported market trades of these instruments.
The aggregate estimated
fair value of the 7.625% Senior Notes was approximately $430.2 million and $435.0 million as of December 31, 2013 and 2012, respectively, based on reported market trades of these instruments.
(6)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $417.0 million and $413.8
million as of December 31, 2013 and 2012, respectively, based on reported market trades of these instruments.
(7)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $41.7 million and $97.7 million as of December 31, 2013 and 2012,
respectively. Because 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.
Amended Credit Facility
The Company’s Amended Credit Facility has a maturity date of October 31, 2016 and current commitments and borrowing base of $625.0 million. Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR
plus 0.5% to 1.5% and the commitment fee is between 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility were 2.0% and 2.2% for the years ended December 31, 2013 and 2012, respectively.
The borrowing base is required to be re-determined twice per year. Our borrowing base is dependent on our proved reserves and was, as of December 31,
2013, $625.0 million based on our June 30, 2013 proved reserves, adjusted for the sale of our West Tavaputs properties and our hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. Future semi-annual borrowing bases under our Amended Credit Facility will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company.
The Amended Credit Facility also contains certain financial covenants. The
Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance. As of December 31, 2013, the Company had $115.0 million outstanding under the Amended Credit Facility. 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 reduces the current available borrowing capacity of the Amended Credit Facility to $484.0 million.
9.875% Senior Notes Due 2016
On
July 15, 2013, the Company redeemed the entire outstanding $250.0 million principal amount of 9.875% Senior Notes for a redemption price of 104.938% of the principal amount of the notes, or $262.3 million. Unamortized debt discount and deferred financing costs related to the notes resulted in a loss upon settlement of $21.5 million for the year ended December 31, 2013.
5%
Convertible Senior Notes Due 2028
On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. The
Company settled the notes in cash. After the redemption, $25.3 million aggregate principal amount of the Convertible Notes was outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of the Company’s existing and future senior unsecured indebtedness, are senior in right of payment to all of the Company’s future subordinated indebtedness, and are effectively subordinated to all of the
Company’s secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of the Company’s subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.
The
Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. The Company has the right at any time with
at least 30 days’ notice to call the Convertible Notes.
On September 27, 2011, the Company issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625%
Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 beginning April 1, 2012. The 7.625% Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are fully and unconditionally
guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% 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 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. The 7.625% Senior Notes are redeemable at the Company’s option at a redemption price of 103.813% of the principal amount of the notes on October 1, 2015.
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 2022 at par. The 7.0% Senior Notes mature on October 15, 2022. 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 Company’s Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at the
Company's option on October 15, 2017 at a redemption price of 103.5% of the principal amount of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.625% 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 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.
Lease Financing Obligation Due 2020
On July 23, 2012, the Company entered into the Lease Financing Obligation, whereby the Company received $100.8 million
through the sale and subsequent leaseback of existing compressors and related facilities owned by the Company. 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 where the Company may purchase the equipment for $36.6 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. As part of the West Tavaputs Divestiture, the purchaser assumed approximately 51% of the Lease Financing Obligation, including the buy out option, leaving the Company with a balance of $43.3 million at December 31, 2013.
The following table summarizes, for the periods indicated, the cash or accrued portion of interest expense related to the Amended Credit Facility, 9.875% Senior Notes, Convertible Notes, 7.625%
Senior Notes, 7.0% Senior Notes and the Lease Financing Obligation along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense:
Cash interest includes amounts related to interest and commitment fees paid on the Amended Credit Facility and participation
and fronting fees paid on the letter of credit.
(2)
The stated interest rate for the 9.875% Senior Notes was 9.875% per annum with an effective interest rate of 11.2% per annum. The Company redeemed the 9.875% Senior Notes in full on July 15, 2013.
(3)
The
stated interest rate for the Convertible Notes is 5% per annum. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represented the fair value of the equity conversion feature at the time of issue. The stated interest rate of 5% on the Convertible Notes will is the effective interest rate of the $25.3 million remaining principal balance, as the related debt discount was fully amortized as of March 31, 2012.
(4)
The stated interest rate for the 7.625% Senior Notes
is 7.625% per annum with an effective interest rate of 8.0% per annum.
(5)
The stated interest rate for the 7.0% Senior Notes is 7.0% per annum with an effective interest rate of 7.2% per annum.
(6)
The effective interest rate for the Lease Financing Obligation is 3.3% per
annum.
6. Asset Retirement Obligations
A reconciliation of the Company’s asset retirement obligations for the year ended December 31, 2013, 2012 and 2011 is as follows:
Assets and Liabilities Measured on a Recurring Basis
The Company’s financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 5, approximates its fair value due to its floating rate structure based on the LIBOR spread and the Company's borrowing base utilization.
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 utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical expedient for assigning fair value. 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. The Company primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available
information. Given the Company’s historical market transactions, its markets and instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on the observability of those inputs. 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 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. 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. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.
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.
The
following tables set forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities that were measured at fair value on a recurring basis. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value hierarchy levels.
All
fair values reflected in the table above and on the Consolidated Balance Sheets 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 methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.
Level 1 Fair Value Measurements – The Company maintains a non-qualified deferred compensation plan (as discussed in more detail in Note 11) 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 prepayments and other current assets and deferred financing costs and other noncurrent assets on the Consolidated Balance Sheets. The Company also has highly liquid short term investments in money market funds. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs. The money market fund investments are recorded at carrying value, which approximates fair value, and represents Level 1 inputs. The fair values of the
Company’s fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $847.2 million as of December 31, 2013. The fair values of the Company’s fixed rate 9.875% Senior Notes, 7.625% Senior Notes and 7.0% Senior Notes totaled $1,120.7 million as of December 31, 2012. The fair values of the
Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.
Level 2 Fair Value Measurements – The fair value of oil, natural gas and NGL swaps and forwards are estimated using a combined income and market valuation methodology with a mid-market pricing convention based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The
Company utilized the counterparties’ valuations to assess the reasonableness of the Company’s valuations.
There is no active, public market for the Company’s Amended Credit Facility, Convertible Notes or Lease Financing Obligation. The Amended Credit Facility balance of $115.0 million as of December 31, 2013 approximates its fair value due to its floating rate structure. The Convertible Notes fair value of $25.1 million and $25.3 million as of December 31,
2013 and 2012, respectively, are measured based on market-based parameters of the various components of the Convertible Notes and over the counter trades. The Lease Financing Obligation fair values of $41.7 million and $97.7 million as of December 31, 2013 and 2012, 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.
Level 3
Fair Value Measurements – As of December 31, 2013 and 2012, the Company did not have assets or liabilities that were measured on a recurring basis classified under a Level 3 fair value hierarchy.
Assets and Liabilities Measured on a Non-recurring Basis
The Company utilizes fair value on a non-recurring basis to perform impairment tests on its property and equipment when required. During the year ended
December 31, 2013, the Company recorded impairment charges of $226.6 million on proved and unproved oil and gas properties. Included in the total impairment charge of $226.6 million was $209.5 million of impairment charges related to the West Tavaputs area of the Uinta Basin for which the Company utilized third party purchase offers as the basis for determining fair value. This property was sold in December 2013. The inputs used to determine such fair value for other non-recurring impairment tests are primarily based upon internally developed cash flow models as
well as available external market data and would generally be classified within Level 3.
(1) See Note 2 for additional details on impairment expense
recognized.
The Company also applied fair value accounting guidance to measure the assets and liabilities in the 2012 Divestiture. The fair values of these items were primarily determined using the present value of estimated future cash inflows and outflows. Because of the unobservable nature of these inputs, they are classified within Level 3. See Note 4 for additional discussion of the 2012 Divestiture. Additionally, the Company uses fair value to determine the value of its asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to
restore leased property to the contractually stipulated condition and would generally be classified within Level 3.
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 at times may 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.
Deferred
financing costs and other noncurrent assets
5,604
(2,623
)
(1)
2,981
(2)
Total derivative assets
$
40,432
$
(7,471
)
$
32,961
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
$
(4,848
)
$
4,848
(3)
$
—
Derivatives
and other noncurrent liabilities
(3,027
)
2,623
(3)
(404
)
(4)
Total derivative liabilities
$
(7,875
)
$
7,471
$
(404
)
(1)
Amounts
are netted against derivative asset balances with the same counterparty, and therefore, are presented as a net asset on the Consolidated Balance Sheets.
(2)
As of December 31, 2013 and 2012, this line item on the Consolidated Balance Sheets included $19.2 million and $26.8 million of deferred financing costs and other noncurrent assets, respectively.
(3)
Amounts
are netted against derivative liability balances with the same counterparty, and therefore are presented as a net liability on the Consolidated Balance Sheets.
(4)
As of December 31, 2013 and 2012, this line item on the Consolidated Balance Sheets includes $3.5 million and $4.1 million of other noncurrent liabilities, respectively.
The following table summarizes the cash flow hedge gains, net of tax, and
their locations on the Consolidated Balance Sheets and Consolidated Statements of Operations for the periods indicated:
Amount
of Gain (Loss) Reclassified from AOCI into Income (net of tax) (1)(2)
Commodity Hedges
$
4,663
$
50,712
$
62,421
Amount
of Gain (Loss) Recognized in Income on Ineffective Hedges
Commodity Hedges
$
—
$
—
$
1,026
(1)
Presented
net of income tax expense of $2.8 million and $30.5 million and income tax benefit of $4.9 million for the years ended December 31, 2013, 2012 and 2011, respectively.
The
table below summarizes the commodity derivative gains and losses the Company recognized related to its oil, gas and NGL derivative instruments for the periods indicated:
Commodity derivative settlements on derivatives designated as cash flow hedges (1)
$
7,463
$
81,166
$
99,922
Total
commodity derivative gain (loss) (2)
(23,068
)
72,759
(14,263
)
(1)
Included in oil, gas and NGL production
revenues in the Consolidated Statements of Operations.
(2)
Included in commodity derivative gain (loss) in the Consolidated Statements of Operations.
The Company’s derivative financial instruments are generally executed with major financial or commodities trading institutions that 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 9 different counterparties as of December 31, 2013. 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, it 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 for income taxes consisted of the following for the periods indicated:
Income
tax expense 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:
Nondeductible political contributions and lobbying costs
96
271
238
Nondeductible
officer compensation
138
—
—
Other permanent items
52
26
84
Deferred
tax related to the changes in overall state tax rates
(3,851
)
310
(286
)
Other, net
(66
)
(114
)
26
Income
tax expense
$
(118,633
)
$
1,636
$
17,672
The tax effects of temporary differences that give rise to significant components of the deferred tax assets
and deferred tax liabilities at December 31, 2013 and 2012 are presented below:
At
December 31, 2013, the Company had approximately $218.0 million of federal tax net operating loss carryforwards that expire through 2033. The Company has a federal alternative minimum tax credit carryforward of $0.7 million, which has no expiration date.
In assessing the realizability of deferred tax assets, 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 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. The Company continues 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. As a result, it may be determined that a deferred tax asset valuation allowance should be established. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. At December 31, 2013, the
Company had approximately $5.9 million of state income tax credit carryforwards that begin expiring in 2017. A valuation allowance against these credits was recorded in 2011. It is currently estimated that the state income tax credits will not be utilized because the Company does not project to have sufficient future taxable income in the appropriate jurisdictions, and therefore the valuation allowance on the full amount of the credit carryforwards will remain.
98
At December 31, 2013, the Consolidated
Balance Sheet reflected a net deferred tax liability of $161.5 million, of which $0.4 million pertains to the tax effects reflected in AOCI.
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 the years ended December 2013, 2012 and 2011.
In 2013, the Company generated no uncertain tax positions. The Company anticipates that no uncertain tax positions will be recognized within the next 12-month period. 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,
2013, 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 2010 through 2013 and is subject to state
tax examination for years 2009 through 2013.
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 150,000,000 shares of common stock, par value $0.001 per share. In October 2004, 150,000
shares of $0.001 per share par value preferred stock were designated as Series A Junior Participating Preferred Stock, none of which are outstanding. The remainder of the authorized preferred stock is undesignated. There are no issued and outstanding shares of preferred stock.
When issued, each share of Series A Junior Participating Preferred Stock will entitle the holder thereof to 1,000 votes on all matters submitted to a vote of the Company’s stockholders.
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, 2013, 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 equity shares of common stock
1,081,259
454,666
353,716
Shares retired or forfeited
(438,301
)
(205,042
)
(222,464
)
Shares
at end of period
49,152,448
48,150,475
47,809,903
Treasury Stock:
Shares
at beginning of period
—
—
—
Treasury stock acquired
96,880
92,393
113,715
Treasury
stock retired
(96,880
)
(92,393
)
(113,715
)
Shares at end of period
—
—
—
99
Accumulated
Other Comprehensive Income. The components of accumulated other comprehensive income and related tax effects for the years ended December 31, 2011, 2012 and 2013 were as follows:
11.
Equity Incentive Compensation Plans and Other Employee Benefits
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).
The following table presents the non-cash stock-based compensation related to equity awards for the periods indicated:
Includes
non-cash stock-based compensation related to director fees of $0.4 million and $0.2 million for the year ended December 31, 2013 and 2012, respectively.
Unrecognized compensation cost as of December 31, 2013 was $19.0 million related to grants of nonvested stock options and nonvested equity shares of common stock that are expected to be recognized over a weighted-average period of 2.3 years.
Stock
Options and Nonvested Equity Shares. 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, and the maximum amount payable to a participant during any calendar year with respect to performance-based or cash incentive awards that are not denominated in common stock or common stock equivalents may not exceed $5.0 million. 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, 2013, 2012 and 2011, the Company did not pay cash to repurchase any stock option exercises.
The fair value of each share-based option award under all of the
Company’s plans is estimated on the date of grant using a Black-Scholes pricing model that incorporates the assumptions noted in the following table. Estimated expected volatilities were based upon historical volatility of the Company’s common stock. The Company does not expect to declare or pay dividends in the foreseeable future; thus, the Company used a 0% expected dividend yield, which is comparable to most of its peers in the industry. The expected terms range from 0.09 years to 6.0 years, or a weighted average of 4.3 years
to 4.6 years, based on 25% of each grant’s vesting on each anniversary date and factoring in potential blackout dates, historic exercises and expectations of future employee behavior. The risk-free rate is based on the U.S. Treasury yield curve in effect on the date of grant and extrapolated to approximate the expected life of the award. The Company estimated a 4% to 10% annual compounded forfeiture rate for the years 2012 and 2011 based on historical employee turnover and actual forfeitures.
2012
2011
Weighted
average volatility
51
%
55
%
Expected dividend yield
—
%
—
%
Weighted average
expected term (in years)
4.3
4.5
Weighted average risk-free rate
1.8
%
1.9
%
A
summary of share-based option activity under all the Company's plans as of December 31, 2013, and changes during the year then ended, is presented below:
Expected
to vest, at December 31, 2013 through the life of the options
1,718,579
28.84
2.59
5,679,748
The per share weighted-average grant date
fair value of options granted for the years ended December 31, 2012 and 2011 were $11.02 and $12.55, respectively. The total intrinsic value of options exercised for the years ended December 31, 2013, 2012 and 2011 were $0.5 million, $0.4 million and $10.0 million, respectively. With respect to stock option exercises, the Company
received $6.4 million, $0.7 million, and $22.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.
A summary of the Company’s nonvested equity shares of common stock as of December 31, 2013, 2012 and 2011, and changes during the years then ended,
is presented below:
Expected
to vest, at December 31, through the life of the awards
661,224
$
22.34
503,412
$
31.08
578,131
$
34.94
Equity
common stock units were issued beginning on July 1, 2012 and will be converted to shares of common stock as they vest. As of December 31, 2013, equity common stock units have only been issued for payment of director fees. A summary of the Company’s nonvested equity share units of common stock as of December 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011 was $8.1 million, $8.6 million and $8.8 million, respectively.
Performance Share Programs
2010 Program. In February 2010, the Compensation Committee of the Board of Directors of the Company approved a performance share program (the “2010 Program”). Upon commencement
of the 2010 Program and during each subsequent year of the 2010 Program through 2013, the Compensation Committee met to approve target and stretch goals for certain operational or financial metrics that are selected by the Compensation Committee for the upcoming year and to determine whether metrics for the prior year have been met. As new goals are established each year for the performance-based awards, a new grant date and a new fair value are created for financial reporting purposes for those shares that could potentially vest in the upcoming year. Compensation expense is recognized based upon an estimate of the extent to which the performance goals would be met. If such goals are not met, no compensation expense is recognized and any previously recognized compensation expense is reversed.
The 2010 Program has both performance-based and market-based goals. All compensation
expense related to the market-based goals will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. Based on Company performance in 2011, 26.6% of the 2010 Program performance shares vested in February 2012. Accordingly, the Company recognized non-cash stock-based compensation of costs associated with those shares of $0.2 million and $2.4 million for the years ended December 31, 2012 and 2011, respectively. Based upon the Company’s performance in 2012, none of the
2010 Program performance shares vested in February 2013.
In February 2013, the Compensation Committee established vesting terms of the Company’s nonvested equity awards in the 2010 Program that are subject to a market performance-based vesting condition, which is based on the Company’s total shareholder return (“TSR”) ranking relative to a defined peer group’s individual TSRs (“Relative TSR”). In February 2013,
22,710
market-based nonvested equity shares of common stock became subject to a new grant date, and the fair value of the shares was remeasured at the grant date. All shares that remain unvested based on 2013 performance will expire in 2014. The fair value of the market-based awards is amortized ratably over the remaining requisite service period. All compensation expense related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. Based on the Company's performance in 2013, 19.8% of the 2010 Program performance shares will vest in February 2014. Accordingly, the Company recorded $0.1 million of non-cash stock-based compensation
expense related to these awards for the year ended December 31, 2013.
In February 2013, the Compensation Committee approved the performance metrics used to measure potential vesting of the performance shares in the 2010 Program based on 2013 performance. For the year ended December 31, 2013, the performance goals consisted of the Company’s TSR ranking relative to a defined peer group’s individual TSR (weighted at 40%), the Company’s discretionary cash flow (weighted at 30%)
and PV10 of proved oil, natural gas and NGL reserves (weighted at 30%). In February 2013, 86,223 performance-based nonvested equity shares of common stock in the 2010 Program became subject to a new grant date, and the fair value of the shares was remeasured at the grant date. All remaining unvested shares could potentially vest if all performance goals are met at the stretch level, and all shares that remain unvested based on 2013 performance will expire in 2014. 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 discretionary cash flow metric and the proved oil, natural gas and NGL reserves metric will be based upon the number of shares expected to vest at the end of the one year period. The
Company recorded $0.3 million of non-cash stock-based compensation expense related to these awards during the year ended December 31, 2013.
2012 Program. In March 2012, the Compensation Committee approved a new performance share program (the “2012 Program”). The performance-based awards contingently vest in May 2015, 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, 2014, consist of the Company’s TSR ranking relative to a defined peer group’s individual TSR (weighted
at 33 1/3%), the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group’s percentage calculation (weighted at 33 1/3%) and percentage change in proved oil and natural gas reserves per debt adjusted share (weighted at 33 1/3%). fifty percent of the total award will vest for performance met at the threshold level, 100% will vest at the target level and 200% will vest 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 shares will be adjusted on a prorated basis of the actual results compared to the threshold, target and stretch goals. If the
threshold metrics are not met, no shares will vest. In any event, the total number of shares of common stock that could vest will not exceed 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that have not vested will be forfeited. A total of 179,798 shares were granted under this program during the year ended December 31, 2012. The Company recorded $0.2 million and $0.5 million of non-cash stock-based compensation expense related to these awards for the years ended December 31, 2013 and 2012,
respectively.
2013 Program. In February 2013, the Compensation Committee approved a new performance share program (the “2013 Program”) pursuant to the 2012 Incentive Plan. The performance-based awards contingently vest in May 2016, 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, 2015, consist of the Company’s Relative TSR (weighted at 33 1/3%), 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 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 will 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 will 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 actual results for a metric are between the threshold and target levels or between the target and stretch levels, the vested
number of shares will be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics are not met, no shares will vest. In any event, the total number of shares of common stock that could vest will not exceed 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that have not vested will be forfeited. A total of 450,544 shares were granted under this program during the year ended December 31, 2013. All compensation expense related to the Relative 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 and the Reserves per Debt Adjusted
Share metric will be based upon the number of shares expected to vest at the end of the three year period. The Company recorded $1.6 million of non-cash stock-based compensation expense related to these awards for the year ended December 31, 2013.
A summary of the Company's non-vested performance-based equity shares of common stock as of December 31, 2013, 2012 and 2011, and changes
during the years then ended, is presented below:
Expected
to vest, at December 31, through the life of the awards
522,312
$
22.14
87,522
$
25.33
183,178
$
33.37
(1)
As
the Compensation Committee approved new performance metrics for the vesting of performance shares in the upcoming year, a new grant date was then created for any unvested awards that were granted in previous years, and a new fair value was established for financial reporting purposes.
The fair value of the performance-based shares vested in the years ended December 31, 2012 and 2011 was $2.6 million and $3.1 million, respectively.
Director Fees. The
Company’s non-employee, or outside, directors, may elect to receive all or a portion of their annual retainer and meeting fees in the form of restricted stock units (“RSUs”), which are settled with shares of the Company’s common stock, issued pursuant to the Company’s 2012 Incentive Plan. After each quarter, RSUs with a value equal to the fees payable for that quarter, calculated using the closing price for the Company’s common stock on the last trading day of the quarter, will be delivered to each outside director who elected before that quarter to receive RSUs for payment of director fees. These nonvested RSUs will vest immediately at the end of the applicable quarter. Once vested, the RSUs will settle
at the end of the applicable quarter or such later date elected by the director.
A summary of the Company’s directors’ fees and equity-based compensation for the years ended December 31, 2013, 2012 and 2011 is presented below:
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 upon 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, with 50% of the match made with the Company’s 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 and common stock contributions of $1.9 million, $2.0 million and $1.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.
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 of the Company’s Board of Directors. 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,
2013 and 2012:
12.
Significant Customers and Other Concentrations
Significant Customers. During 2013, one customer individually accounted for over 10% of the Company's oil, gas and NGL production revenues. During 2012, two customers individually accounted for over 10% of the Company’s oil, gas and NGL production revenues. During 2011, three customers individually accounted for over 10% of the
Company’s oil, gas and NGL production revenues. Although diversified among many companies, collectability is dependent upon the financial stability of each individual company and is influenced by the general economic conditions of the industry. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.
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 hedges in place with 9 different counterparties, of which all are lenders or affiliates of lenders in the Amended Credit Facility. 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 an ISDA master agreement or other contracts.
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 are presented below:
Gathering,
Transportation and Processing Charges. The Company has entered into contracts that provide firm gathering and transportation capacity on pipeline systems and firm processing charges. The remaining terms on these contracts range from 2 to 8 years and require the Company to pay gathering, transportation and processing charges regardless of the amount of pipeline capacity utilized by the Company. The
Company paid $42.6 million, $45.0 million and $35.3 million of firm gathering and transportation charges for the years ended December 31, 2013, 2012 and 2011, respectively. The Company paid $4.6 million, $6.2 million and $5.0 million of firm processing charges for the years ended December 31, 2013, 2012
and 2011, respectively. All gathering and transportation costs, including demand charges and processing charges, are included in gathering, transportation and processing expense in the Consolidated Statements of Operations.
The amounts in the table below represent the Company’s gross future minimum transportation demand and firm processing charges. However, the Company will record in its financial statements only the Company’s proportionate share based on the Company’s working interest and net revenue interest, which will vary from property
to property.
Lease
and Other Commitments. The Company has one take-or-pay purchase agreement for supply of carbon dioxide (“CO2”), which has a total financial commitment of $1.7 million as of December 31, 2013. The CO2 is for use in fracture stimulation operations. Under this contract, the Company is obligated to purchase a minimum monthly volume at a set price. If the Company takes delivery of less than the minimum required amount, the
Company is responsible for full payment (deficiency payment) in December 2015.
The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. Office lease expense was $1.8 million, $2.0 million and $1.5 million for the years ended December 31, 2013, 2012 and 2011, 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:
Includes a drilling carry agreement in the amount of $8.5 million related to acreage in the Powder River Basin. As of December 31, 2013, the Company has satisfied $1.6 million
of this carry. The Company will owe the remaining carry balance if not satisfied by October 1, 2015.
(2)
The total includes the lease payments for 19,200 square feet of the Denver office which is under a sublease agreement as of December 31, 2013.
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 7.625% Senior Notes, the 7.0% Senior Notes and the Convertible Notes, which are registered securities, are jointly and severally
guaranteed on a full and unconditional basis by the 100% owned subsidiaries (“Guarantor Subsidiaries”) of the Company (referred to in this Note 14 as the “Parent Issuer”). 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 Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
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.
Additions to oil and gas properties, including acquisitions
(884,099
)
(63,107
)
—
(947,206
)
Additions
to furniture, fixtures and other
(11,556
)
414
—
(11,142
)
Proceeds from sale of properties and other investing activities
1,702
—
—
1,702
Cash
flows from financing activities:
Proceeds from debt
800,000
—
—
800,000
Principal
and redemption premium payments on debt
(330,000
)
—
—
(330,000
)
Intercompany transfers
(69,973
)
69,973
—
—
Other
financing activities
5,938
1
—
5,939
Change in cash and cash equivalents
(1,409
)
50
—
(1,359
)
Beginning
cash and cash equivalents
58,690
—
—
58,690
Ending cash and cash equivalents
$
57,281
$
50
$
—
$
57,331
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, 2013, 2012 and 2011 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 2013, 2012 and 2011.
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas 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:
The
increase in NGL revisions of previous estimates includes the impact of the Company's conversion to three stream production. Prior to 2013, NGL reserves were included in natural gas data, which impacts the comparability for the periods presented.
At December 31, 2013, the Company revised its proved reserves upward by 2.2 MMBoe. The Company also revised its 2013 proved reserves upward by 0.2
MMBoe, as 2013 pricing was $3.67 per MMBtu and $96.91 per barrel of oil compared with the 2012 pricing of $2.56 per MMBtu and $91.21 per barrel of oil. Prices were adjusted by lease for quality, transportation fees and regional price differences.
At December 31, 2012, the Company revised its proved reserves downward by 15.0 MMBoe, excluding pricing revisions, due primarily to negative
engineering revisions related to the 20-acre infill drilling performance at the West Tavaputs field in the Uinta Basin. At December 31, 2012, the Company also revised its 2012 proved reserves downward by 13.9 MMBoe, as 2012 pricing was $2.56 per MMBtu and $91.21 per barrel of oil compared with the 2011 pricing of $3.93 per MMBtu and $92.71 per barrel of oil. Prices were adjusted by lease for quality, transportation fees and regional
price differences.
At December 31, 2011, the Company revised its proved reserves upward by 6.3 MMBoe, excluding pricing revisions, due primarily to the positive results of increased operational focus and engineering and geological study of the Company's Blacktail Ridge field in the Uinta Basin. At December 31,
2011, the Company also revised its 2011 proved reserves upward by 0.9 MMBoe, as 2011 pricing was $3.93 per MMBtu and $92.71 per barrel of oil compared with the 2010 pricing of $3.95 per MMBtu and $75.96 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, 2013, 2012 and 2011, 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, 2013, calculations were made using adjusted average prices of $83.35 per Bbl for oil, $29.60 per Bbl for NGLs and $3.14 per MMBtu for gas, as compared to the average benchmark prices of $96.91 per Bbl for oil, $39.75 per Bbl for NGLs and $3.67 per Mcf for gas. For the year ended December 31, 2012, calculations were made using adjusted average prices of $78.85 per Bbl for oil and $3.68 per MMBtu for gas, as compared to the average benchmark
prices of $91.21 per Bbl for oil and $2.56 per Mcf for gas. For the year ended December 31, 2011, calculations were made using adjusted average prices of $78.04 per Bbl for oil and $5.16 per MMBtu for gas, as compared to the average benchmark prices of $92.71 per Bbl for oil and $3.93 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
$
1,377,549
$
1,166,703
$
1,616,088
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
$
1,166,703
$
1,616,088
$
1,132,366
Sales
of oil and gas, net of production costs and taxes
(393,451
)
(414,662
)
(493,278
)
Extensions, discoveries and improved recovery, less related costs
584,379
251,460
307,013
Quantity
revisions
(23,484
)
(603,726
)
78,062
Price revisions
448,883
(371,954
)
417,174
Previously
estimated development costs incurred during the period
100,320
413,543
197,994
Changes in estimated future development costs
(33,455
)
82,202
(182,991
)
Accretion
of discount
140,120
211,735
149,637
Purchases of reserves in place
—
3,358
166,662
Sales
of reserves
(475,396
)
(296,788
)
—
Changes in production rates (timing) and other
126
8,690
(19,293
)
Net
changes in future income taxes
(137,196
)
266,757
(137,258
)
Standardized measure of discounted future net cash flows, end of period
$
1,377,549
$
1,166,703
$
1,616,088
Quarterly
Financial Data
The following is a summary of the unaudited quarterly financial data, including income before income taxes, net income and net income per common share for the years ended December 31, 2013 and 2012.
