|BILL BARRETT CORP filed this Form 10-K on 03/02/2017|
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the fiscal year ended December 31, 2016
Commission file number 001-32367
BILL BARRETT CORPORATION
(Exact name of registrant as specified in its charter)
(Registrant's telephone number, including area code)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes þ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
o Yes þ No
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
o Yes þ No
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2016 was $374,175,332 (based on the closing price of $6.39 per share as of the last business day of the fiscal quarter ended June 30, 2016)
As of February 14, 2017, the registrant had 75,720,644 outstanding shares of $0.001 per share par value common stock.
DOCUMENTS INCORPORATED BY REFERENCE
The information required in Part III of this Annual Report on Form 10-K is incorporated by reference from the registrant's definitive proxy statement for the registrant's Annual Meeting of Stockholders to be held in May 2017 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant's fiscal year ended December 31, 2016.
GLOSSARY OF OIL, NATURAL GAS AND NGL TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and gas industry:
Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume.
Bcf. Billion cubic feet of natural gas.
Boe. Barrel of oil equivalent, determined by converting gas volumes to barrels of oil equivalent using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Boe/d. Boe per day.
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Coalbed methane. Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and can be produced into a pipeline.
Completion. Refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Drill-to-earn. The process of earning an interest in leasehold acreage by drilling a well pursuant to a farm-in, exploration, or other agreement.
Dry hole or Dry well. An exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
EBITDAX. Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.
EHS. Environmental Health and Safety.
Environmental Assessment. A study that can be required prior to drilling a federal well.
Environmental Impact Statement. A more detailed study of the potential direct, indirect and cumulative impacts of a federal project that is subject to public review and potential litigation.
EPA. The United States Environmental Protection Agency.
E&P waste. Exploration and production waste, intrinsic to oil and gas drilling and production operations.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Henry Hub. The Erath, LA settlement point price as quoted in Platt's Gas Daily.
Horizontal drilling. A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill bit to drill horizontally within a designated zone typically defined as the prospective pay zone to be completed for oil and or gas.
Hydraulic fracturing. The injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas and oil production.
Identified drilling locations. Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.
Infill drilling. The addition of wells in a field that decreases average well spacing. This practice both accelerates expected recovery and increases estimated ultimate recovery in heterogeneous reservoirs by improving the continuity between injectors and producers. As well spacing is decreased, the shifting well patterns alter the formation-fluid flow paths and increase sweep to areas where greater hydrocarbon saturations exist.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. Thousand barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.
Mcf. Thousand cubic feet of natural gas.
MMBbls. Million barrels of crude oil or other liquid hydrocarbons.
MMBoe. Million barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.
MMBtu. Million British thermal units.
MMcf. Million cubic feet of natural gas.
Mt. Belvieu. The Mt. Belvieu, TX settlement point price as quoted by Oil Price Information Service.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.
Net revenue interest. An owner's interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
NGLs. Natural gas liquids.
NWPL. Northwest Pipeline Corporation price as quoted in Platt's Inside FERC.
Percentage of proceeds contracts. Under percentage of proceeds (POP) contracts, processors receive an agreed upon percentage of the actual proceeds of the sale of the dry natural gas and NGLs.
Play. A term used to describe an accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Productive well. Producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking, unless the specific circumstances justify a longer time. No proved undeveloped reserves can be attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Resource Management Plan. A document that describes the U.S. Bureau of Land Management's intended uses of lands that are under its jurisdiction.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
SEC. U.S. Securities and Exchange Commission.
Standardized Measure. The present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner of such interest the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner of such interest to pay a share of the costs of drilling and production operations.
WTI. West Texas Intermediate price as quoted on the New York Mercantile Exchange.
WTI Cushing. The West Texas Intermediate price at the Cushing, OK settlement point as quoted by Bloomberg, using crude oil price bulletins.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, (the "Securities Act"), Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements about our future strategy, plans, estimates, beliefs, timing and expected performance.
All statements in this report, other than statements of historical fact, are forward-looking statements. Forward-looking statements may be found in "Items 1 and 2. Business and Properties", "Item 1A. Risk Factors", "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and other sections of this Annual Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as "expect", "seek", "believe", "upside", "will", "may", "expect", "anticipate", "plan", "will be dependent on", "project", "potential", "intend", "could", "should", "estimate", "predict", "pursue", "target", "objective", or "continue", the negative of such terms or other comparable terminology.
Forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the following risks and uncertainties:
In light of these and other risks, uncertainties and assumptions, anticipated events addressed in forward looking statements may not occur.
The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that our expectations will be realized or that future forward-looking events and circumstances will occur as anticipated. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to many factors including those listed above and in "Item 1A. Risk Factors" and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Readers should not place undue reliance on these forward-looking statements, which reflect management's views only as of the date hereof. Other than as required under the securities laws, we do not intend to, and do not undertake any obligation to, update or revise any forward-looking statements as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
Items 1 and 2. Business and Properties.
Bill Barrett Corporation together with our wholly-owned subsidiaries ("the Company", "we", "our" or "us") is an independent energy company that develops, acquires and explores for oil and natural gas resources. All of our assets and operations are located in the Rocky Mountain region of the United States.
We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.
We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders expectations and regulatory requirements.
Oil prices declined significantly in 2014 and 2015 and remained depressed during 2016. Natural gas and NGL prices have experienced decreases of comparable magnitude over the same period. During the last three months of 2016, commodity prices improved slightly and stabilized at a level that could warrant increased activity, however, we expect to be flexible with our 2017 capital budget as we continue to monitor economic conditions.
In 2017, our priority remains ensuring ample liquidity and protecting the strength of our balance sheet, and we will adjust our development plans as necessary to this end. In addition, we expect to pursue opportunities to further improve our liquidity position through capital markets or other transactions, such as additional property dispositions, if we believe conditions to be favorable.
We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed an initial public offering. In December 2016, we completed an additional public offering, selling 15,525,000 shares at a price of $7.40 per share, par value $0.001 per share. The sale included the full exercise by the underwriters of their option to purchase 2,025,000 shares of common stock. Net proceeds from the sale, after deducting fees and estimated expenses, were approximately $109.8 million. Our common stock is traded on the New York Stock Exchange under the symbol "BBG". The principal executive offices are located at 1099 18th Street, Suite 2300, Denver, Colorado 80202, and the telephone number at that address is (303) 293-9100.
We maintain a website at the address http://www.billbarrettcorp.com. We are not including the information contained on our website as part of, or incorporating it by reference into, this report. We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC via EDGAR and posted at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines and the charters of our Audit Committee, Compensation Committee, Reserves and EHS Committee and Nominating and Corporate Governance Committee are posted on our website and are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 1099 18th Street, Suite 2300, Denver, Colorado 80202. We intend to disclose on our website any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K. This Annual Report on Form 10-K and our website contain information provided by other sources that we believe are reliable. We cannot assure you that the information obtained from other sources is accurate or complete. No information on our website is incorporated by reference herein or deemed to be part of this Annual Report on Form 10-K.
We operate in one industry segment, which is the exploration, development and production of oil and natural gas, and all operations are conducted in the United States. Consequently, we currently report a single reportable segment. See "Financial 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, 2016:
Areas of Operation
As of December 31, 2016, we have two key areas of production: The Denver-Julesburg Basin ("DJ Basin") and the Uinta Oil Program in the Uinta Basin.
The following table shows changes in the mix of oil, natural gas and NGLs for both production and reserves over the periods presented:
wells are turned to production we expect to temporarily have a higher percentage of natural gas and NGLs. As a result of limited drilling activity in 2016, we only had 23.8 net wells turned to production in 2016.
The Company's acreage positions in the DJ Basin are predominantly located in Colorado's eastern plains and parts of southeastern Wyoming.
Our DJ Basin acreage was acquired predominantly through two acquisitions completed in August 2011 and July 2012. During the year ended December 31, 2015, we sold certain non-core assets in two separate transactions closing on October 21, 2015 and November 30, 2015, respectively for aggregate cash proceeds of $29.5 million, after closing adjustments. These asset sales included approximately 23,000 net acres (76% proved developed) and interests in legacy vertical producing wells.
The DJ Basin is a high growth oil development area where operators are targeting the Niobrara and Codell formations and employing new technologies to optimize oil recoveries and economic returns. We believe that the DJ Basin offers us significant growth opportunities with potential acreage additions to our current leasehold position, possible development of additional formations, increased utilization of extended reach (long lateral) horizontal wells, well completion optimization and ongoing cost reduction.
The DJ Basin is a core area of operation where we drilled 17 gross (15.1 net) operated wells and completed 24 gross (23.4 net) operated wells in 2016. The Company had one rig operating at the beginning of 2016 but due to the uncertainty of an oil price recovery during 2016, the Company elected to curtail drilling activity to preserve capital, and released the drilling rig during the first quarter of 2016. As industry conditions improved during the latter part of 2016, drilling resumed with a one rig program through the remainder of 2016. In 2016, we focused on drilling extended reach horizontal wells in the Niobrara B and Niobrara C formations and initial tests in the Niobrara A and Codell formations in the Northeast Wattenberg area of the DJ Basin, continuing to optimize our completion technology and establishing a scalable development program. The combination of this development along with nearby competitor activity continued to de-risk our acreage in the area.
We expect the 2017 drilling program to be more active relative to 2016. Currently we are utilizing one rig in the DJ Basin. Our capital budget contemplates adding an additional rig in the second quarter of 2017; however, we may elect to accelerate or delay drilling depending on industry conditions. The 2017 operated drilling program will focus on drilling extended reach wells (9,200 foot laterals) and assumes 53 to 64 acre well density. In addition, we anticipate minimal participation in non-operated wells. We may modify this program throughout 2017 as business conditions and operating results warrant.
Our oil production from the DJ Basin is sold at the lease and trucked to markets. Our gas production from the DJ Basin is gathered and processed by a third party and we receive residue gas and NGL revenue under percentage of proceeds contracts.
The Uinta Basin is located in northeastern Utah.
The Uinta Oil Program includes one area of development located in the Uinta Basin that we refer to as East Bluebell. On July 14, 2016, we sold certain non-core assets located in the Uinta Basin, which included approximately 40,000 net acres and interests in producing wells for cash proceeds of $28.3 million. The divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized in 2017.
The Uinta Oil Program has a sizable acreage position with a long-term drilling inventory and a significant resource in place. The resource is a stacked oil play with multiple pay zones, and our drilling program targets multiple zones from the Upper and Lower Green River formations with vertical wells.
In 2017, the Company has no plans to drill and develop any acreage other than a few recompletions, and we anticipate minimal participation in non-operated wells. This program may be modified throughout 2017 as business conditions and operating results warrant.
Our oil production in the Uinta Basin is sold at the lease and trucked to markets. Our gas production in the Uinta Basin is gathered and processed by various third parties, and we receive residue gas and NGL revenue under percentage of proceeds contracts.
Oil and Gas Data
The following table presents our estimated net proved oil, natural gas and NGL reserves at each of December 31, 2016, 2015 and 2014 based on reserve reports prepared by us and audited by independent third party petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our reserve estimates independently audited, such an audit is required under our Amended Credit Facility. All of our proved reserves included in our reserve reports are located in North America. Netherland, Sewell & Associates, Inc., ("NSAI"), audited all of our reserves estimates at December 31, 2016, 2015 and 2014. NSAI is retained by and reports to the Reserves and EHS Committee of our Board of Directors, which is comprised of independent directors. When compared on a well-by-well or lease-by-lease basis, some of our internal estimates of net proved reserves are greater and some are less than NSAI's estimates. However, in the aggregate, NSAI's estimates of total net proved reserves are within 10% of our internal estimates. In addition to a third party audit, our reserves are reviewed by our Reserves and EHS Committee. The Reserves and EHS Committee reviews the final reserves estimates in conjunction with NSAI's audit letter and meets with the key representative of NSAI to discuss NSAI's review process and findings.
The data in the above table represent estimates only. Oil, natural gas and NGLs reserve engineering is an estimation of accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered. See "Item 1A. Risk Factors".
The following tables illustrate the history of our proved undeveloped reserves from December 31, 2014 through December 31, 2016:
the current business plan. It is anticipated that with a more active development program than was employed during 2016, the Company will add additional PUD locations during 2017.
At December 31, 2016, our proved undeveloped reserves were 18.5 MMBoe. At December 31, 2015, our proved undeveloped reserves were 43.9 MMBoe. During 2016, 8.5 MMBoe, or 19% of our December 31, 2015 proved undeveloped reserves (21 wells), were converted into proved developed reserves and required $55.3 million of drilling and completion capital and $5.3 million of facilities capital. These wells produced 1.3 MMBoe in 2016. During 2016, we added 8.4 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. Negative engineering revisions decreased proved undeveloped reserves by 0.7 MMBoe. During 2016, 24.3 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Negative pricing revisions decreased proved undeveloped reserves by 0.3 MMBoe. The proved undeveloped reserves from December 31, 2015 that remained in the proved undeveloped reserves category at December 31, 2016 were 9.6 MMBoe.
At December 31, 2015, our proved undeveloped reserves were 43.9 MMBoe. At December 31, 2014, our proved undeveloped reserves were 80.8 MMBoe. During 2015, 8.1 MMBoe, or 10% of our December 31, 2014 proved undeveloped reserves (35 wells), were converted into proved developed reserves and required $165.3 million of drilling and completion capital and $5.0 million of facilities capital. These wells produced 0.9 MMBoe in 2015. During 2015, we added 2.6 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. Positive engineering revisions increased proved undeveloped reserves by 1.3 MMBoe. During 2015, 14.7 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans and were either traded, sold or removed. This volume includes 12.2 MMBoe of proved undeveloped reserves sold in the divestiture of our non-core DJ and Uinta Basin properties. Negative pricing revisions decreased proved undeveloped reserves by 18.0 MMBoe. The proved undeveloped reserves from December 31, 2014 that remained in the proved undeveloped reserves category at December 31, 2015 were 40.8 MMBoe.
At December 31, 2014, our proved undeveloped reserves were 80.8 MMBoe. At December 31, 2013, our proved undeveloped reserves were 113.7 MMBoe. During 2014, 10.2 MMBoe, or 9% of our December 31, 2013 proved undeveloped reserves (65 wells), were converted into proved developed reserves and required $227.5 million of drilling and completion capital and $9.5 million of facilities capital. These wells produced 0.9 MMBoe in 2014. During 2014, we added 12.5 MMBoe of proved undeveloped reserves due to drilling programs in our core oil and gas development areas. During 2014, 36.6 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans and were either traded, sold or removed. This volume includes 27.7 MMBoe of proved undeveloped reserves sold in the divestiture of our Piceance and Powder River Basin properties. Negative engineering and pricing revisions decreased proved undeveloped reserves by 6.0 MMBoe. In addition, we added 7.4 MMBoe of proved undeveloped reserves as a result of acquired property in the DJ Basin. The proved undeveloped reserves from December 31, 2013 that remained in the proved undeveloped reserves category at December 31, 2014 were 66.8 MMBoe.
We use our internal reserves estimates rather than the estimates of an independent third party engineering firm because we believe that our reservoir and operations engineers are more knowledgeable about the wells due to our continual analysis throughout the year as compared to the relatively short term analysis performed by third party engineers. We use our internal reserves estimates on all properties regardless of the positive or negative variance relative to the estimates of third party engineers. If a variance greater than 10% occurs at the field level, it may suggest that a difference in methodology or evaluation techniques exists between us and the third party engineers. We investigate any such differences and discuss the differences with the third party engineers to confirm that we used the proper methodologies and techniques in estimating reserves for the relevant field. These variances also are reviewed with our Reserves and EHS Committee. These differences are not resolved to a specified tolerance at the field or property level. In the aggregate, the third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates.
The internal review process of our wells and the related reserves estimates, and the related internal controls we utilize, include but are not limited to the following:
Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is William K. Stenzel. Mr. Stenzel is our Senior Vice President of Corporate Development and Planning and became responsible for our reserves estimates starting in September 2014. Mr. Stenzel earned a Bachelor of Science degree in Civil Engineering from Colorado State University in 1977. Mr. Stenzel has over 39 years of experience in reserves and economic evaluations, as well as a broad experience in production, completions, reservoir analysis and planning and development.
The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Dan Paul Smith and Mr. John G. Hattner. Mr. Smith, a Licensed Professional Engineer in the State of Texas (No. 49093), has has been practicing consulting petroleum engineering at NSAI since 1980 and has over 7 years of prior industry experience. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991, and has over 11 years of prior industry experience. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of
Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
NSAI performed a well-by-well audit of all of our properties and of our estimates of proved reserves and then provided us with its audit report concerning our estimates. The audit completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be the same or different from audit procedures performed by other independent third party engineering firms for other oil and gas companies. NSAI's audit report does not state the degree of its concurrence with the accuracy of our estimate of the proved reserves attributable to our interest in any specific basin, property or well.
The NSAI audit process is intended to determine the percentage difference, in the aggregate, of our internal net proved reserves estimate and future net revenue (discounted at 10%) and the reserves estimate and net revenue as determined by NSAI. The audit process includes the following:
The reserves audit letter provided by NSAI states that "in our opinion the estimates shown herein of Bill Barrett's reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards." The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.
Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown in the Financial Statements should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements ("FASB"), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
From time to time, we engage NSAI to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its employees have no interest in those properties, and the compensation for these engagements is not contingent on NSAI's estimates of reserves and future cash inflows for the subject properties. During 2016 and 2015, we paid NSAI approximately $150,000 and $200,000, 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:
processing expense and since that date have instead been included in unused commitments expense in the Consolidated Statements of Operations.
The following table sets forth information at December 31, 2016 relating to the productive wells in which we owned a working interest as of that date.
Developed and Undeveloped Acreage
The following table sets forth information as of December 31, 2016 relating to our leasehold acreage.
Substantially all of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth, as of December 31, 2016, the expiration periods of the net undeveloped acres by area that are subject to leases summarized in the above table of undeveloped acreage.
The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities or value of reserves found.
In general, we serve as operator of wells in which we have a greater than 50% working interest. In addition, we seek to be operator of wells in which we have lesser interests. As operator, we obtain regulatory authorizations, design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or the majority of the other oil field service equipment used for drilling or maintaining wells on the properties we operate. Independent contractors engaged by us provide the majority of the equipment and personnel associated with these activities. We construct, operate and maintain gas gathering and water facilities associated with our operations. We employ drilling, production and reservoir engineers and geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.
Marketing and Customers
We market all of the oil production from our operated properties. Our natural gas and related NGLs are generally marketed by third parties under percentage of proceeds ("POP") contracts. We sell our oil production to a variety of purchasers under contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. Purchasers include pipelines, processors, refineries, marketing companies and end users. We normally sell production to a relatively small number of customers, as is customary in the development and production business. Our natural gas and related NGLs are sold primarily to one gas gathering and processing company. Based on where we operate and the availability of other purchasers and markets, we believe that our production can be sold in the market in the event that it is not sold to our existing customers. However, in some circumstances, a change in customers may entail significant transition costs during the transition to a new customer.
During 2016, three customers individually accounted for over 10% of the Company's oil, gas and NGL production revenues. During 2015, four customers individually accounted for over 10% of the Company's oil, gas and NGL production revenues. During 2014, two customers individually accounted for over 10% of the Company's oil, gas and NGL production revenues.
We enter into hedging transactions with unaffiliated third parties for portions of our production to achieve more predictable cash flows and to reduce our exposure to fluctuations in commodities prices. For a more detailed discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk".
Our oil production is collected in tanks on location and sold to third parties that collect the oil in trucks and transport it to pipelines, rail terminals and refiners. We sell our oil production to a variety of purchasers under monthly, annual or multi-year terms. Our oil contracts are priced off of either New York Mercantile Exchange ("NYMEX") or area oil posting with quality, location or transportation differentials.
The following table sets forth information about material long-term firm natural gas pipeline transportation contracts, which entail a demand charge for reservation of capacity. These contracts were initiated to provide a guaranteed outlet for company marketed production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of our Piceance Basin assets in September 2014 (see Note 4 of the Notes to Consolidated Financial Statements for more information related to these divestitures). Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. Beginning October 1, 2014, and as a result of our divestitures of the associated gas assets, these transportation costs were excluded from gathering, transportation and processing expense and since that date have instead been included in unused commitments expense in the Consolidated Statements of Operations.
Our hedging program is intended to mitigate the risks of volatile prices of oil, natural gas, and NGLs. As of February 14, 2017, we have hedged 2,406,875 barrels of oil and 3,650,000 MMbtu of natural gas or approximately 50% of our expected 2017 production and 864,250 barrels of oil for our 2018 production at price levels that provide some economic certainty to our cash flows. To date six of our 13 lenders (or affiliates of lenders) under our credit facility are also hedging counterparties. We are not required to post collateral for these hedges other than the security for our credit facility. For additional information on our hedging activities, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk".
The oil and gas industry is intensely competitive, and we compete with a large number of other companies, some of which have greater resources. See the risk discussed below in “Item 1A. Risk Factor s” under the caption “Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed”.
Title to Properties
As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved developed reserves. Prior to the commencement of drilling operations on those properties, we typically conduct a title examination and perform curative work for significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing such defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we utilize methods consistent with practices customary in the oil and gas industry and that our practices are adequately designed to enable us to acquire satisfactory title to our producing properties. Prior to completing an acquisition of producing oil and gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil, natural gas and NGL producing properties are subject to customary royalty and other interests, liens for current taxes, liens under our Amended Credit Facility and other burdens that we believe do not materially interfere with the use of our properties.
Environmental Matters and Regulation
General. Our operations are subject to comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment, management of E&P waste, or otherwise relating to environmental protection and minimization of aesthetic impacts. Our operations are generally subject to the same environmental laws and regulations as other companies in the oil and gas exploration and production industry. These laws and regulations:
other protected areas, including areas proximate to residential areas and certain high-occupancy buildings;
These laws, rules and regulations may also restrict the rate of oil, natural gas and NGLs production below the rate that would otherwise be possible, for example, by limiting the flaring of associated natural gas from an oil well while awaiting a pipeline connection. The regulatory burden on the oil and gas industry increases the cost and timing of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.
We believe that we are, and have historically been, in substantial compliance with all applicable environmental laws and regulations. We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not extraordinary. We believe that our compliance with existing requirements has been accounted for and will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of any more stringent future laws and regulations. For the year ended December 31, 2016, we did not incur any material capital expenditures for remediation of well sites or production facilities or to retrofit emission control equipment at any of our facilities.
The environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:
National Environmental Policy Act. Oil, natural gas and NGLs exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of the Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and project alternatives. If impacts are considered significant, the agency will prepare a more detailed Environmental Impact Statement. These environmental analyses are made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that trigger the requirements of NEPA. Certain federal permits on non-federal lands may also trigger NEPA requirements. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.
Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of "hazardous wastes" and on the disposal of non-hazardous wastes. Under the oversight of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with RCRA or corresponding state programs. RCRA also imposes cleanup liability related to the mismanagement of regulated wastes. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy are currently exempt from regulation under the hazardous waste provisions of RCRA, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to reverse the exemption. In addition, certain environmental groups have petitioned and sued the EPA to reverse the exemption.
We believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we have held, and continue to hold, all necessary and up-to-date approvals, permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory
reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, imposes strict, joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be potentially responsible for a release or threatened release of a "hazardous substance" (generally excluding petroleum) into the environment. These persons may include current and past owners or operators of a disposal site, or site where the release or threatened release of a "hazardous substance" occurred, and companies that disposed of or arranged for the disposal of the hazardous substance at such sites. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims under CERCLA and/or state common law for cleanup costs, personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, could be subject to CERCLA. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such "hazardous substances" have been released.
Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced water, storm water drainage and other oil and gas wastes, into Waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws also prohibit the discharge of dredge and fill material in regulated waters, including jurisdictional wetlands, unless authorized under a permit issued by the U.S. Army Corps of Engineers ("Corps"). Federal and state regulatory agencies can impose administrative penalties, civil and criminal penalties, and take judicial action for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. The EPA and the Corps finalized a federal rulemaking to revise the jurisdictional definition of "Waters of the United States" in June 2015. The final rule currently is stayed and not effective pending ongoing litigation. The final rule, if and when effective, may expand the definition of "Waters of the United States" to include certain waters, including wetlands and tributaries not currently regulated. This definition would subject certain activities in those waters to permitting under the Clean Water Act, including permitting under Section 404 of the Clean Water Act for various activities, including wetlands development. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs may also limit the total volume of water or fill material that can be discharged, hence limiting the rate of development.
Air Emissions. The Federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits, emission reporting, and the imposition of emission control requirements. Most of our facilities are now required to obtain permits before work can begin, and existing facilities are often required to incur additional capital costs in order to maintain compliance with laws and regulations. In 2012, the EPA issued new New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) specific to the oil and gas industry, including air standards for natural gas wells that are hydraulically fractured, and issued several amendments to the NSPS rules in 2013 and 2014, respectively. In addition, the EPA has deemed carbon dioxide ("CO2") and other greenhouse gases, including methane, to be a danger to public health, which is leading to regulation of greenhouse gases in a manner similar to other pollutants. For example, the EPA finalized new regulations focused on methane emissions from the oil and gas industry in June 2016. The Bureau of Land Management also finalized similar methane and gas-capture rules for oil and gas operations on federal and tribal leases and certain committed state or private tracts in a federally approved unit or communitized agreement. The EPA already requires reporting of greenhouse gases, such as CO2 and methane, from operations. In February 2014, Colorado expanded its oil and gas air regulations, including the adoption of the first set of fugitive methane emission control regulations in the United States and the EPA and the State of Utah currently are examining additional air quality regulations that might affect our Uinta Basin operations. In addition, the EPA has lowered the national ambient air quality standard for ozone pollution, which may require the oil and gas industry to further reduce emissions of volatile organic compounds and nitrogen oxides. Further, Colorado's ozone non-attainment status was bumped-up from "marginal" to "moderate," which triggers significant additional obligations for the State under the Clean Air Act. These state and federal regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations.
Hydraulic Fracturing. Our completion operations are subject to regulation, which may increase in the short or long-term. The well completion technique known as hydraulic fracturing is used to stimulate production of natural gas and oil and has come under increased scrutiny by the environmental community, as well as local, state and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into prospective rock formations at depth
to stimulate oil and natural gas production. We use this completion technique on substantially all of our wells to obtain commercial production.
Under the direction of Congress, the EPA has undertaken a study of the effect, if any, of hydraulic fracturing on drinking water and groundwater and released its preliminary report in 2015, finding no systematic impact on groundwater resources. In its final report, issued in late 2016, EPA removed the conclusion of no systemic impact from the executive summary of the report, although it cited no new evidence to the contrary. In April 2015, EPA has also published proposed pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations. Congress may consider legislation to amend the Federal Safe Drinking Water Act or the Toxic Substances Control Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have already issued such disclosure rules. Several environmental groups have also petitioned the EPA to extend release reporting requirements under the Emergency Planning Community Right-to-Know Act to the oil and gas extraction industry and in 2015, EPA granted, in part, one of these petitions to add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under the Toxic Release Inventory ("TRI"). On January 6, 2017, EPA issued a proposed rule to include natural gas processing facilities within the TRI program. In addition, the Department of the Interior finalized expanded or new regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes some of the lands on which we conduct or plan to conduct operations. These regulations have been stayed pending ongoing litigation. In Colorado, certain local jurisdictions imposed moratoria or bans on hydraulic fracturing, all of which have been invalidated, including on appeal to the Colorado Supreme Court. In 2016, citizen initiatives to empower local governments to regulate or prohibit oil and gas development, and to impose a 2,500’ statewide setback from occupied buildings and a variety of water ways and other natural resource areas failed to attract enough signatures to be certified for the ballot. On the other hand, another ballot initiative, supported by the industry and business community, as well as a number of elected officials made the ballot and was approved by the electorate. This “Raise the Bar” initiative will make it much more difficult to qualify ballot initiatives to amend the state constitution, or to enact such measures into law. Nonetheless, disputes at the local level regarding high-intensity oil and gas development in proximity to residential areas have not subsided and local ordinances or state legislation may be proposed that could result in additional restrictions on oil and gas development in some areas of Colorado. The Company participates in industry organizations mobilized to combat such measures, including by litigation where necessary.
Climate Change. In June 2014, the U.S. Supreme Court upheld a portion of the EPA's greenhouse gas regulatory program for certain major sources in the Utility Air Regulatory Group v. EPA case. The EPA has finalized significant new rules to curb carbon emissions from power plants and other industrial activities, known as the Clean Power Plan, which in February 2016 was stayed by the U.S. Supreme Court. In addition, certain environmental groups are agitating for scaling back, or eliminating, fossil fuel extraction and use, including efforts to convince policy-makers that the majority of known oil and gas reserves must never leave the ground. These groups are mobilizing around a movement for global divestment from fossil fuel companies, which, if effective, could affect the market for our securities. Recently, the University of Colorado and the University of Denver have rejected proposed divestment measures. In addition, in December 2015 the United States reached agreement during the United Nations climate change conference in Paris to make a 26-28% reduction in its greenhouse gas emissions by 2025 against a 2005 baseline. Potential future laws, regulations or even litigation addressing greenhouse gas emissions could impact our business by limiting emissions of methane, restricting the flaring or venting of natural gas, or by reducing demand for oil or natural gas.
Homeland Security. Legislation continues to be introduced in Congress, and development of regulations continues in the Department of Homeland Security and other agencies, concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Cybersecurity has been a topic of increased focus, and we implemented several cybersecurity measures, including an emergency response plan in 2016. Presently, it is not possible to accurately estimate the costs we could incur to comply with other security laws or regulations, but such expenditures could be substantial.
Other Regulation of the Oil and Gas Industry
Our operations are subject to other types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, bonds securing plugging, abandonment and reclamation obligations, and reports concerning our operations. Most states, and some counties, municipalities and Native American tribes also regulate one or more of the following:
State laws regulate the size and shape of drilling and spacing units or proration units governing well density and location, as well as the pooling of oil and natural gas properties. Some states provide statutory mechanisms for compulsory pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, compulsory pooling or unitization may be implemented by third parties and subject our interest to third party operations. While not currently an issue in Colorado or Utah, other states establish maximum rates of production from oil and natural gas wells and impose requirements regarding ratable takes by purchasers of production. Such laws and regulations, if adopted in Colorado or Utah, might limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, our production is generally subject to multiple layers of severance and/or ad valorem taxation by states, counties and tribes.
Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission ("FERC"), has jurisdiction over the transportation and sale or resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for "first sales" of domestic natural gas, which include all of our sales of our own production.
The Energy Policy Act of 2005 (the “EPAct 2005”) was signed into law in August 2005. The EPAct 2005 amends the Natural Gas Act to make it unlawful for “any entity”, including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. The EPAct 2005 also gives FERC authority to impose civil penalties for violations of the Natural Gas Act or Natural Gas Policy Act up to $1 million per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, thus reflecting a significant expansion of FERC’s enforcement authority.
FERC also regulates interstate natural gas transportation rates and service conditions pursuant to the Interstate Commerce Act ("ICA"), 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, non-preferential transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company, and pursuant to the ICA and its implementing regulations are required to file the tariff rates and other terms and conditions of such services with FERC. FERC's initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach pursued by FERC and Congress over the past few decades will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes may have on our natural gas-related activities.
Operations on Native American Reservations. In 2016, we divested a majority of our Utah assets located on tribal lands. Certain of our remaining assets are subject to EPA air quality regulations applied to “Indian Country” generally, and such regulations may result in permitting delays and additional expenditures on emission controls.
As of February 14, 2017, we had 111 employees of whom 76 work in our Denver office and 35 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, 2016, we leased approximately 81,833 square feet of office space in Denver, Colorado at 1099 18th Street, where our principal offices are located. The lease for our Denver office expires in March 2019. We also own field offices in Roosevelt, Utah and Greeley, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.
Annual CEO Certification
As required by New York Stock Exchange rules, on May 23, 2016, we submitted an annual certification signed by our Chief Executive Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.
Item 1A. Risk Factors.
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only risks facing the Company. Additional risks not presently known to us or that we currently consider immaterial also may adversely affect our Company.
Risks Related to the Oil and Natural Gas Industry and Our Business
Oil and gas prices are volatile and can significantly affect our financial results and estimated proved oil and gas reserves.
Our revenue, profitability and cash flow depend upon the prices for oil, natural gas and NGLs. The markets for these commodities are very volatile, based on supply and demand, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil, natural gas and NGL prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil, natural gas and NGLs may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
Lower oil, natural gas and NGL prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil, natural gas and NGLs that we can produce economically and the estimated value of future cash flows from our reserves. This may result in our having to make substantial downward adjustments to the estimated quantity and value of our proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration or development results deteriorate, successful efforts accounting rules may require us to write down or impair, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management's plans change with respect to those assets. We recorded impairment charges of $572.4 million in the year ended December 31, 2015 on our proved and unproved oil and gas properties, and may record similar charges in the future.
Oil prices declined significantly in 2014 and 2015 and remained depressed during 2016. In response, we suspended drilling activities in March 2016. Drilling was resumed in August 2016. In late 2016, leading up to and following an OPEC agreement to restrict production, oil prices began to recover. Natural gas and NGL prices have also fallen significantly since mid-2014. These decreases have increased the volatility and amplitude of the other risks facing us as described in this report and have impacted our business and financial condition. If oil prices decrease from current levels, our planned drilling projects may
become uneconomic, which could affect future drilling plans and growth rates. Low commodity prices impact our revenue, which we partially mitigate with our hedging program. Continued low commodity prices make it more challenging to hedge production at higher price levels. For example, the weighted average fixed price for our oil hedge contracts scheduled to settle in 2017 is $58.59 compared to $76.88 in 2016.
Our drilling efforts and our well operations may not be profitable or achieve our targeted returns.
Drilling for oil, natural gas and NGLs may involve unprofitable efforts from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether oil, natural gas or NGLs are present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Drilling results in some of our plays may be more uncertain than in other plays that are more mature and have longer established drilling and production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other formations to maximize recoveries will be ultimately successful when used in our prospects. As a result, we may incur future dry hole costs and or impairment charges due to any of these factors.
We have acquired significant amounts of proved and unproved property in order to attempt to further our exploration and development efforts. Drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire proved and unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. We cannot guarantee that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that proved or unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, that we will recover all or any portion of our investment in such proved or unproved property or wells, or that we will succeed in bringing on additional partners.
Substantially all of our producing properties are located in the Rocky Mountain region, making us vulnerable to risks associated with operating in one major geographic area.
Our operations are focused on the Rockies, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil, natural gas and NGLs produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation and processing, and any resulting delays or interruptions of production from existing or planned new wells.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business and the recording of proved reserves.
Our exploration, development, production and marketing operations are subject to extensive environmental regulation at the federal, state and local levels including those governing emissions to air, wastewater discharges, hazardous and solid wastes, remediation of contaminated soil and groundwater, protection of surface and groundwater, land reclamation and preservation of natural resources. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, permit, design, drill, install, operate and abandon oil and natural gas wells and related facilities. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects, leading to delays.
Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.
Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and refineries owned and operated by third parties. Our Uinta oil production has a high paraffin content which limits the number of refiners able to purchase it as feedstock. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured or under-insured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
We have elected, and may in the future elect, not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. For example, we do not carry business interruption insurance for these reasons. In addition, pollution and environmental risks generally are not fully insurable. Further, we could be unaware of a pollution event when it occurs and therefore be unable to report the event within the time period required under the relevant policy. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations and overall financial condition.
Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil, natural gas and NGL reserves.
The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the development, production and acquisition of oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with sales of our equity and debt securities, proceeds from bank borrowings, sales
of properties and cash generated by operations. Our cash flow from operations and access to capital is subject to a number of variables, including:
If our revenues or the borrowing base under our Amended Credit Facility decreases as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. We may, from time to time, need to seek additional financing. Our Amended Credit Facility and senior note indentures place certain restrictions on our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing. Recent commodity price decreases have made it substantially more difficult for us and other industry participants to raise capital, and will likely have an adverse effect on our borrowing base.
If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our Amended Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil, natural gas and NGLs reserves as well as our revenues and results of operations.
Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGLs prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas and NGLs from these or any other potential drilling locations. As such, our actual drilling activities may differ materially from those presently identified, which could adversely affect our business.
Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed.
The oil and gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for, develop and produce oil, natural gas and NGLs, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies are able to pay more for producing oil, natural gas and NGLs properties and exploration and development prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil, natural gas and NGLs market prices. Our larger or integrated competitors are better able than we are to absorb the burden of existing and any changes to federal, state, local and Native American tribal laws and regulations, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial resources than many companies in our industry, we may be at a disadvantage in bidding for producing properties and exploration and development prospects.
The willingness and ability of our lenders to fund their lending obligations under our revolving Amended Credit Facility may be limited, which would affect our ability to fund our operations.
Our Amended Credit Facility has commitments from 13 lenders. If credit markets become turbulent as a result of an economic downturn, delayed economic recovery, lower commodity prices or other factors, our lenders may become more restrictive in their lending practices or may be unwilling or unable to fund their commitments, which would limit our access to
capital to fund our capital expenditures, operations or meet other obligations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and potentially losses.
A U.S. and global economic downturn could have a material adverse effect on our business and operations.
Any or all of the following may occur if, as a result of a crisis in the global financial and securities markets, a deterioration in national or global growth prospects or other factors, an economic downturn occurs:
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these assumptions will materially affect the quantities of our reserves.
Underground accumulations of oil, natural gas and NGLs cannot be measured in an exact way. Oil, natural gas and NGLs reserve engineering requires estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGLs prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect.
Our estimates of proved reserves are determined at prices and costs at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates of reserves. We prepare our own estimates of proved reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see "Items 1 and 2. Business and Properties-Oil and Gas Data-Proved Reserves" and "Supplementary Information to Consolidated Financial Statements-Supplementary Oil and Gas Information (unaudited)-Analysis of Changes in Proved Reserves" in this Annual Report on Form 10-K.
At December 31, 2016, approximately 34% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $170.0 million during the five years ending December 31, 2021. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC's reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame.
Unless we replace our oil, natural gas and NGLs reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
Producing oil, natural gas and NGL reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil, natural gas and NGL reserves and production, and therefore our cash flow and income are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.
Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers.
One of our strategies is to capitalize on opportunistic acquisitions of oil, natural gas and NGLs reserves. Our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remaining properties for reserve potential. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.
Our hedging activities could result in financial losses or could reduce our income.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a portion of our production revenues. Hedging arrangements for a portion of our production revenues expose us to the risk of financial loss in some circumstances, including when:
In addition, these types of hedging arrangements limit the benefit we would receive from increases in commodities prices and may expose us to cash margin requirements if we hedge with counterparties who are not parties to our credit facility.
Our counterparties are financial institutions that are lenders under our Amended Credit Facility or affiliates of such lenders. The risk that a counterparty may default on its obligations was heightened by the financial sector crisis of 2008-2009, and losses incurred by many banks and other financial institutions, including some of our counterparties or their affiliates. These
losses may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which would reduce our revenues from hedges at a time when we are also receiving a lower price for our production revenues, thus triggering the hedge payments. As a result, our financial condition could be materially adversely affected.
Federal legislation may decrease our ability, and increase the cost, to enter into hedge transactions.
The Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank") was signed into law in July 2010. Dodd-Frank regulates derivative transactions, including our commodity derivative swaps. We expect that Dodd-Frank and its implementing regulations will increase the cost to hedge as a result of fewer counterparties being in the market and the pass-through of increased capital costs of bank subsidiaries. The imposition of margin requirements or other restrictions on our hedging activities could make hedging more expensive or impracticable. A reduction in our ability to enter into hedging transactions would expose us to additional risks related to commodity price volatility and impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from oil, natural gas and NGLs sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil, natural gas and NGLs hedging arrangements expose us to credit risk in the event of nonperformance by counterparties. An economic downturn and/or an extended period of low commodity prices would increase these risks.
We face risks related to rating agency downgrades.
If one or more rating agencies downgrades our outstanding debt, future debt issuance could become more difficult and more costly. Also, we may be required to provide collateral or other credit support to certain counterparties, which would increase our costs and limit our liquidity.
Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.
As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information, acquire cash or other assets through theft or fraud or render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, corruption of data or misappropriation of assets. There can be no assurance that the procedures and controls we use to monitor and mitigate these risks will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, assets, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
Land owner demands arising as a result of a recent decision of the Wyoming Supreme Court could have adverse effects on our business.
In December 2015, the Wyoming Supreme Court issued its "Pennaco" decision, the essence of which is that parties to a contract, such as a surface use agreement, remain liable for the obligations under that agreement - even when the agreement and the underlying assets have been sold and assigned to a third party - unless the agreement contains express language releasing and discharging the original party upon such subsequent assignment.
Landowners across Wyoming are making Pennaco claims against companies that sold assets to other oil and gas companies that are now in default. To date, our exposure relates to coalbed methane ("CBM") leases and wells that we sold to entities which are now essentially defunct, if not in actual bankruptcy proceedings. These operators have defaulted on several annual surface use payments, as well as leaving more than 150 CBM wells acquired from us in non-producing (shut-in) status. We have been contacted by several large ranches or their attorneys demanding payment of amounts in arrears, and that we conduct the plugging of the wells and land reclamation. Each case entails determining what contractual obligations are imposed by the applicable surface use agreement, taking into account state and federal plugging and reclamation requirements.
We obtained orders from the Wyoming Oil & Gas Conservation Commission ("WOGCC") requiring certain of the defaulting operators to "show cause" as to why the WOGCC should not authorize us to take over the wells in order to conduct plugging and reclamation operations. In response to these orders, we have reached contractual agreements that provide us with the authority to plug and abandon any or all of the wells at issue. We are exploring a number of options including investigating third party interest in acquiring the wells, assumption of obligations related to the shallow CBM wells by operators holding "deep rights" under the leases, and negotiated settlement and release agreements with the ranches. It should also be noted that the WOGCC holds substantial plugging bonds posted by the defaulting operators. The Company is under no regulatory compulsion to plug these wells at this time.
At this time, we do not believe that resolving this matter will have a material financial impact. We believe that, if necessary, the currently identified roster of shut-in wells can be plugged and reclaimed at cost of approximately $15,000 per well. There is no assurance, however, that this issue will not expand to wells sold to other purchasers of Wyoming assets previously owned by the Company.
Possible future ballot initiatives in Colorado, if approved, could have severely adverse effects on our operations, reserves and financial condition.
As previously disclosed, several statewide ballot initiatives were filed for the 2016 election cycle that sought to restrict or limit oil and natural gas development in Colorado. Proponents attempted to collect the required number of signatures to have two such proposals included on the ballot for the November 2016 election. One would have amended the Colorado constitution to impose a 2,500 foot statewide drilling setback from occupied structures and other sensitive areas. If implemented, this proposal would have had the effect of rendering the vast majority of the surface area of the state ineligible for drilling, including many of our planned future drilling locations. The second would have amended the state constitution to give local governmental authorities the ability to regulate, or to ban, oil and gas development activities within their boundaries notwithstanding state rules to the contrary. If implemented, this proposal could have caused us to be subject to onerous, and possibly inconsistent, regulations that vary from jurisdiction to jurisdiction, or to outright bans on our activities in the state. The Colorado Secretary of State determined that proponents of these proposals did not submit a sufficient number of valid signatures for the proposals to be included on the November 2016 ballot. However, similar proposals, or other proposals limiting oil and natural gas development activities, could be made in the future, although qualifying such initiatives to amend the state constitution is now much more difficult. Because substantially all of our operations and reserves are located in Colorado, the passage and implementation of any such proposal could have a materially adverse effect on our operations, reserves, financial condition and business generally.
Risks Related to Our Common Stock
Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.
Delaware corporate law and our current certificate of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:
These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions that are opposed by our board. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, and this may limit the price that investors are willing to pay in the future for shares of our common stock.
Risks Related to our Senior Notes, Convertible Notes, Lease Financing Obligations and Amended Credit Facility
We may not be able to generate enough cash flow to meet our debt obligations, including our obligations and commitments under our senior notes and our Amended Credit Facility.
We expect our earnings and cash flow could vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may be insufficient to meet our debt obligations and commitments, including our 7.625% Senior Notes due 2019 ("7.625% Senior Notes"), our 7.0% Senior Notes due 2022 ("7.0% Senior Notes"), and our Amended Credit Facility. Any insufficiency could negatively impact our business. A range of economic, competitive, business, and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to repay our debt. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control. In particular, these risks have been significantly exacerbated by the sustained decline in commodity prices.
As of December 31, 2016, the total outstanding principal amount of our indebtedness was approximately $718.7 million, and we had approximately $274.0 million in additional borrowing capacity under our Amended Credit Facility, which, if borrowed, would be secured debt effectively senior to the Senior Notes 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, 2016, $300.0 million based on our July 31, 2016 proved reserves and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. As of December 31, 2016, we had no amounts outstanding under our Amended Credit Facility.
The borrowing base is set at the sole discretion of the lenders. Our next scheduled borrowing base redetermination is scheduled on or about April 1, 2017 based on proved reserves as of December 31, 2016 at updated bank price decks and hedge position. However, in the event of lower capital investment in our properties due to a sustained cycle of low commodity prices, we could see lower quantities of proved developed reserves which would, in combination with lower oil and gas commodity pricing, lead to lower borrowing bases.
If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake one or more alternative financing plans, such as:
However, any alternative financing plans that we undertake, if necessary, may not be completed in a timely manner or at all, and even if completed may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.
Our debt could have important consequences. For example, it could:
We may be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing the notes and our Amended Credit Facility impose on us.
The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on the 2017 budget at current commodity prices. However, if commodity prices significantly decline, EBITDAX will be significantly reduced, which is a critical underpinning of our required financial covenants. If this were to occur, it will make it necessary for us to negotiate an amendment to one or more of these financial covenants.
If we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt.
If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt or take other actions to pay the accelerated debt. Even if new financing were available at that time, it may not be on terms that are acceptable to us. A breach of any covenant would also limit the funds available under our Amended Credit Facility. In September 2015, we obtained an amendment to the Amended Credit Facility that replaced our debt-to-EBITDAX covenant in the facility for a limited period of time. Through March 31, 2018, the covenants are secured debt-to-EBITDAX and EBITDAX-to-interest. There can be no assurance that we will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.
Risks Related to Tax
We may incur more taxes if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation or if additional taxes are imposed on us.
Proposals are made from time to time to eliminate 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:
It is unclear whether any of the foregoing changes will be enacted or how soon any such changes could become effective. Any such change could negatively impact our financial condition and results of operations by increasing the costs we incur, which in turn could make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.
Our utilization of net operating loss and tax credit carryforwards may be limited based on current Internal Revenue Code restrictions
The Company has significant net operating loss ("NOL") carryforwards. Subject to certain limitations and applicable expiration dates, these tax attributes can be carried forward to reduce the Company's federal income tax liability for future periods. Under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), the Company's NOL carryforwards would become subject to the "section 382 limitation" if the Company were to experience an "ownership change." For this purpose, the term "ownership change" refers to an increase in ownership of at least 50% of the Company's shares by certain groups of shareholders during any three-year period, as determined under certain conventions. As of December 31, 2016, the Company believes it has not experienced an ownership change under Section 382.
If the Company were to undergo an ownership change at any time under Section 382 of the Code, the Company's NOL carryforwards could only be used to offset an amount of income equal to the "section 382 limitation" in each taxable year. Any NOL carryforwards that could not be used as a result of the section 382 limitation would carry forward to future years, still subject to the same section 382 limitation, unless and until they expire unused. The Company's "section 382 limitation" would generally equal the fair market value of the Company's outstanding equity (as of the date of the ownership change) multiplied by a certain interest rate (as of the date of the ownership change) published monthly by the U.S. Treasury Department and known as the "long-term tax exempt rate."
The Company expects to have sufficient income to utilize its alternative minimum tax credit, which may be carried forward indefinitely, subject to section 383 limitations.
Item 1B. Unresolved Staff Comments.
Item 3. Legal Proceedings.
We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.
Item 4. Mine Safety Disclosures.
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:
On February 14, 2017, the closing sales price for our common stock as reported by the NYSE was $5.96 per share.
Holders. On February 14, 2017, the number of holders of record of our common stock was 102.
Dividends. We have not paid any cash dividends since our inception. Because we anticipate that all earnings will be retained for the development of our business and our debt agreements limit the payment of cash dividends, we do not expect that any cash dividends will be paid on our common stock for the foreseeable future.
Unregistered Sales of Securities. There were no sales of unregistered equity securities during 2016 except pursuant to the Debt Exchange disclosed in our Current Report on Form 8-K filed with the SEC on June 2, 2016.
Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2016:
Stockholder Return Performance Presentation
As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:
Item 6. Selected Financial Data.
The following table presents our selected historical financial data for the years ended December 31, 2016, 2015, 2014, 2013 and 2012. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines, properties acquired or sold and other factors. This information should be read in conjunction with the consolidated financial statements and notes thereto and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" presented elsewhere in this Annual Report on Form 10-K.
Selected Historical Financial Information
The consolidated statement of operations information for the years ended December 31, 2016, 2015 and 2014 and the balance sheet information as of December 31, 2016 and 2015 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, 2013 and 2012 and the balance sheet information at December 31, 2014, 2013 and 2012 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.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with the "Selected Financial Data" and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the "Cautionary Note Regarding Forward-Looking Statements" at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in "Items 1 and 2. Business and Properties - Business - Operations - Environmental Matters and Regulation;" "Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry;" and "Item 1A. Risk Factors" above, all of which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.
We develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.
We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering. In December 2016, we completed an additional public offering of our common stock, selling 15,525,000 shares at a price of $7.40 per share, par value $0.001 per share. The sale included the full exercise by the underwriters of their
option to purchase 2,025,000 shares of common stock. Net proceeds from the sale, after deducting fees and estimated expenses, were approximately $109.8 million.
Oil prices declined significantly in 2014 and 2015 and remained depressed during 2016. Natural gas and NGL prices have experienced decreases of comparable magnitude over the same period. During the last three months of 2016, commodity prices improved slightly and stabilized at a level that could warrant increased activity, however, we expect to be flexible with our 2017 capital budget as we continue to monitor economic conditions.
In 2017, our priority remains ensuring ample liquidity and adjusting our development plans as necessary to this end. In addition, we expect to pursue opportunities to further improve our liquidity position through capital markets or other transactions, such as additional property dispositions, if we believe conditions to be favorable. On October 28, 2016, the borrowing base under our Amended Credit Facility was reduced to $300.0 million based on proved reserves in place at July 31, 2016. Our available borrowings under the re-determined borrowing base of $300.0 million is reduced by $26.0 million to $274.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement.
We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders expectations and regulatory requirements.
Future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, sales of properties, other indebtedness, and/or debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.
Because of our growth through acquisitions and, more recently, development of our properties and sales of properties in 2014 and 2015, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not indicative of future results.
The following table summarizes the estimated net proved reserves and related Standardized Measure for the years indicated. The Standardized Measure is not intended to represent the current market value of our estimated oil and natural gas reserves.
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:
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:
Commodity prices are inherently volatile and are influenced by many factors outside of our control. As of February 14, 2017, we have hedged 2,406,875 barrels of oil and 3,650,000 MMbtu of natural gas or approximately 50% of our expected 2017 production and 864,250 barrels of oil for our 2018 production at price levels that provide some economic certainty to our cash flows. We focus our efforts on increasing oil, natural gas and NGLs reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.
On July 14, 2016, we closed on the sale of certain non-core assets in the Uinta Basin. Total gross consideration, after initial closing adjustments, was $33.1 million, including cash proceeds of $28.3 million and $4.8 million related to the relief of asset retirement obligations.
Results of Operations
Year Ended December 31, 2016 Compared with Year Ended December 31, 2015
The following table sets forth selected operating data for the periods indicated: