UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 2014
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition Period From to
Commission File No. 333-186686
SAMSON RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
Delaware | 45-3991227 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer identification No.) |
Samson Plaza
Two West Second Street
Tulsa, OK 74103-3103
(Address and zip code of registrants principal executive offices)
(918) 591-1791
(Registrants 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. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x
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. Yes x 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). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer | ¨ | Accelerated filer | ¨ | |||
Non-accelerated filer | x (Do not check if a smaller reporting company) | Smaller reporting company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
As of March 15, 2015, Samson Resources Corporation had 845,600,000 shares of common stock outstanding.
SAMSON RESOURCES CORPORATION
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Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations |
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk |
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures |
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Item 10. Directors, Executive Officers and Corporate Governance |
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Item 13. Certain Relationships and Related Transactions, and Director Independence |
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Certification of CEO Pursuant to Rule 13a-14(a) |
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Certification of CFO Pursuant to Rule 13a-14(a) |
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Certification of CEO Pursuant to Rule 13a-14(b) |
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Certification of CFO Pursuant to Rule 13a-14(b) |
1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
The information in this report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements included in this report, other than statements of historical fact, may constitute forward-looking statements, including, but not limited to, statements or information regarding our future growth, results of operations, operational and financial performance, business prospects and opportunities and future events. Words such as, but not limited to, anticipate, continue, estimate, expect, may, might, will, project, should, believe, intend, continue, could, plan, predict, potential, goal, foresee and negatives of these words and similar expressions are intended to identify forward-looking statements. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. These statements are based on, but not limited to, managements assessment of such factors as the condition of our industry and the competitive environment. These assessments could prove inaccurate.
All forward-looking statements involve risks and uncertainties. The occurrence of the events described and the achievement of the expected results depend on many events and assumptions, some or all of which are not predictable or within our control. Although the forward-looking statements contained in this report reflect our current beliefs based upon information currently available to us and upon assumptions which we believe to be reasonable, actual results may differ materially from expected results.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil and natural gas. Factors that may cause actual results to differ from expected results include, but are not limited to: (i) our substantial indebtedness; (ii) our ability to refinance, restructure or amend our indebtedness or otherwise improve our capital structure and liquidity; (iii) our ability to generate or obtain sufficient cash to service our indebtedness and other obligations; (iv) fluctuations in oil and natural gas prices; (v) restrictions contained in our debt agreements; (vi) the uncertainty inherent in estimating our reserves, future net revenues and discounted future cash flows; (vii) the timing and amount of future production of oil and natural gas; (viii) cash flow and changes in the availability and cost of capital; (ix) environmental, drilling and other operating risks, including liability claims as a result of our oil and natural gas operations; (x) proved and unproved drilling locations and future drilling plans; (xi) the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation; (xii) our ability to make acquisitions and divestitures on favorable terms or at all; and (xiii) any of the risk factors and other cautionary statements described under Part I, Item 1ARisk Factors in this report or in any other report, registration statement or other document that we may file from time to time with the Securities and Exchange Commission (the SEC).
Readers are cautioned not to place undue reliance on forward-looking statements. Should one or more of the risks or uncertainties referenced above occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Further, new factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible to predict all such factors, or to the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement.
All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Each forward-looking statement speaks only as of the date of this report, and, except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.
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GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:
Basin. A large natural depression on the earths surface in which sediments generally brought by water accumulate.
Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Bcfe/d. Bcfe per day.
Btu. One British thermal unit, which is the quantity of heat required to raise the temperature of a one pound mass of water by one degree Fahrenheit.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil and/or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Delay rental. A payment under an oil and gas lease by the lessee to the lessor for the privilege of deferring the commencement of drilling operations or the commencement of production during the primary term of the lease.
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 an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
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 natural gas in another reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
Formation. A layer of rock which has distinct characteristics that differs from nearby rock.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.
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Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBbl. One million barrels of crude oil, condensate or natural gas liquids.
MMBtu. One million British thermal units.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMcfe/d. Mmcfe per day.
Natural gas liquids or NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells. An owner who has 50% interest in 100 acres has 50 net acres.
NYMEX. The New York Mercantile Exchange.
Potential drilling locations. The gross resource play locations that we potentially may be able to drill on our existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. Productive wells include producing wells and wells that are mechanically capable of production.
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. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulationsprior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved undeveloped reserves (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.
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.
Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.
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Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
Spud. The commencement of drilling operations of a new well.
Standardized measure of discounted future net cash flows. The standardized measure provides value-based information about proved oil and gas reserves based on estimates of future cash flows from production of proved reserves assuming continuation of year-end economic and operating conditions.
Tcfe. One trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Unit. The joining of all or substantially all interests in a particular spacing or development area or section, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement or pooling order.
Wellbore. The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.
Working interest. The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
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Unless the context requires otherwise, in this report, references to (i) Samson, the Company, we, us and our refer to Samson Resources Corporation and its consolidated subsidiaries and (ii) natural gas or gas include natural gas liquids, which we sometimes refer to as NGLs. Certain other operational and industry terms used in this report are defined above under Glossary of Oil and Natural Gas Terms.
ITEM 1. | BUSINESS |
Overview
We are an independent oil and gas company engaged in the exploration, development and production of oil and natural gas properties located onshore in the United States. We operate our business and properties through our West Division, which includes properties primarily in the Rocky Mountain region, and our East Division, which includes properties primarily in the Mid-Continent and East Texas regions.
As of December 31, 2014, we had proved reserves of approximately 1.5 Tcfe. Approximately 12.9% of our net proved reserves were oil, 14.3% were natural gas liquids and 72.8% were natural gas. Our net daily production for the year ended December 31, 2014 averaged approximately 530 MMcfe per day, including approximately13,674 Bbls per day of oil and approximately 12,792 Bbls per day of natural gas liquids. As of December 31, 2014, we owned interests in approximately 7,354 gross (3,289 net) productive wells, with approximately 81% of our net production operated by Samson. During 2014, we completed 107 gross (80 net) operated wells.
The table below provides certain selected operational information for the periods indicated.
Year Ended December 31, 2014 |
As of December 31, 2014 | |||||||||||||||
Average Net Daily Production (MMcfe/d) |
Proved Reserves (Bcfe) |
Proved Developed Reserves (%) |
Net Acreage (in thousands) |
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West Division Business Units: |
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Williston |
25 | 83 | 56 | % | 98 | |||||||||||
Powder River |
27 | 58 | 91 | % | 292 | |||||||||||
Greater Green River |
53 | 104 | 87 | % | 211 | |||||||||||
San Juan |
80 | 198 | 99 | % | 55 | |||||||||||
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Total West Division |
185 | 443 | 88 | % | 656 | |||||||||||
East Division Business Units: |
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Mid-Continent West |
80 | 260 | 76 | % | 173 | |||||||||||
Mid-Continent East |
102 | 255 | 90 | % | 278 | |||||||||||
East Texas |
161 | 533 | 82 | % | 360 | |||||||||||
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Total East Division |
343 | 1,048 | 83 | % | 811 | |||||||||||
Other(1) |
2 | 1 | | 101 | ||||||||||||
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Total |
530 | 1,492 | 84 | % | 1,568 | |||||||||||
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(1) | Other reflects our interests in certain non-core assets located throughout the continental United States. |
Corporate History
Samson Resources Corporation, a Delaware corporation, was formed in November 2011 in connection with the acquisition of Samson Investment Company from its selling stockholders (the Acquisition) by certain
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affiliates of Kohlberg Kravis Roberts & Co. L. P. (KKR), ITOCHU Corporation (ITOCHU) and certain other co-investors. In December 2011, the Acquisition closed and Samson Investment Company became a direct, wholly-owned subsidiary of Samson Resources Corporation, with KKR and certain other co-investors, including investment funds affiliated with Crestview Partners II GP, L.P. and Natural Gas Partners IX, L.P., holding their shares of common stock of Samson Resources Corporation through Samson Aggregator L.P. (Samson Aggregator) and ITOCHU holding their shares of common stock of Samson Resources Corporation through JD Rockies Resources Limited (JD Rockies). In this report, Samson Aggregator and JD Rockies are sometimes collectively referred to as the Principal Stockholders. For more information about our equity investors, see Part III, Item 12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and Part III, Item 13Certain Relationships and Related Transactions, and Director Independence.
We financed the Acquisition, repaid all of Samson Investment Companys then outstanding long-term indebtedness and paid related fees and expenses with: (i) approximately $1.345 billion of borrowings under a reserves-based borrowing base revolving credit facility (the RBL Revolver); (ii) $2.250 billion of borrowings under a syndicated senior unsecured bridge facility (the Bridge Facility); (iii) $4.145 billion of equity capital from the Principal Stockholders; and (iv) $180.0 million aggregate liquidation preference of cumulative redeemable preferred stock, par value $0.10 per share (the Cumulative Preferred Stock), issued by Samson Resources Corporation to the selling stockholders. In February 2012, we issued $2,250,000,000 aggregate principal amount of 9.750% Senior Notes due 2020 (the Senior Notes) and used the proceeds, together with cash on hand, to repay outstanding borrowings under our Bridge Facility in full and pay related fees and expenses.
Samson Investment Company is a Nevada corporation and was formed in June 1986 as the holding company for a Tulsa, Oklahoma-based oil and natural gas exploration and production business, which had previously been operating since 1971 under our subsidiary, Samson Resources Company. Prior to the Acquisition, Samson Investment Company completed a reorganization transaction, which allowed the selling stockholders to retain certain assets and liabilities associated with its coastal Gulf of Mexico and offshore operations (the Gulf Coast Assets), and, as a result, the Gulf Coast Assets were not included in the Acquisition. In this report, references to Predecessor refer to Samson Investment Company and its consolidated subsidiaries prior to the consummation of the Acquisition.
Our Operations
Estimated Proved Reserves
The following table summarizes our historical estimated proved reserves as of the dates indicated. The estimated proved reserves presented below are based on reports prepared by Netherland, Sewell & Associates, Inc. (NSAI), our independent petroleum engineers. In preparing the reports, NSAI evaluated properties representing all of the Companys reserves as of the dates indicated. The estimated proved reserves presented below include proved reserves attributable to assets divested subsequent to the dates indicated. You should refer to Part I, Item 1ARisk Factors, Part II, Item 7Managements Discussion and Analysis of Financial
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Condition and Results of Operations and Note 23 to our audited consolidated financial statements included Part II, Item 8Financial Statements and Supplementary Data of this report when evaluating the material presented below.
As of December 31, 2014 |
As of December 31, 2013 |
As of December 31, 2012 |
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Estimated proved reserves: |
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Natural gas (Bcf) |
1,086 | 1,246 | 1,323 | |||||||||
Natural gas liquids (MMBbls) |
36 | 50 | 47 | |||||||||
Oil (MMBbls) |
32 | 52 | 68 | |||||||||
Total estimated proved reserves (Bcfe) |
1,492 | 1,857 | 2,014 | |||||||||
Proved developed producing (Bcfe) |
1,247 | 1,216 | 1,297 | |||||||||
Proved developed non-producing (Bcfe) |
6 | 16 | 11 | |||||||||
Proved undeveloped (Bcfe) |
240 | 625 | 707 | |||||||||
Percent proved developed producing reserves |
84 | % | 66 | % | 64 | % |
Development of Proved Undeveloped Reserves
Our estimated proved undeveloped reserves decreased from approximately 625 Bcfe at December 31, 2013 to approximately 240 Bcfe at December 31, 2014. This reduction was primarily due to negative revisions of previous estimates of approximately 333 Bcfe and current year drilling activity. The negative revisions particularly impacted certain of our assets in the Mid-Continent, East Texas, Powder River and Greater Green River Basins formations and principally occurred as a result of enhanced engineering, petrophysical and geological interpretation, operated and non-operated drilling patterns, and offset well analysis. These revisions were offset by additions of approximately 68 Bcfe from extensions and discoveries primarily in the Cotton Valley formation. In addition, approximately 126 Bcfe was converted from undeveloped to developed reserves. The following table summarizes the changes in our estimated proved undeveloped reserves during 2014 (in Bcfe):
Proved undeveloped reserves, December 31, 2013 |
625 | |||
Purchases of reserves in place |
6 | |||
Sales of reserves |
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Extensions and discoveries |
68 | |||
Revisions of previous estimates |
(333 | ) | ||
Conversion to proved developed reserves |
(126 | ) | ||
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Proved undeveloped reserves, December 31, 2014 |
240 | |||
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During 2014, we converted approximately 126 Bcfe of proved undeveloped reserves to proved developed reserves or 20% of our total proved undeveloped reserves booked at December 31, 2013. During 2014, we incurred approximately $558.1 million in drilling and completion capital expenditures, including approximately $253.0 million to convert reserves classified as proved undeveloped as of December 31, 2013 to reserves classified as proved developed as of December 31, 2014. Costs of proved undeveloped reserves development in 2014 do not represent the total costs of these conversions, as additional costs may have been incurred in previous years. For additional information on our capital expenditures, see Part II, Item 7Managements Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources.
As of December 31, 2014, none of our proved undeveloped reserves at December 31, 2014 were scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped.
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Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and guidelines established by the SEC, Netherland, Sewell & Associates, Inc. (NSAI), our independent reserve engineers, estimated 100% of our proved reserve information as of December 31, 2014, 2013 and 2012. As discussed in their biographical information and qualifications provided below, the technical persons responsible for preparing the reserves estimates presented herein 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 Engineers
Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report are Mr. Connor B. Riseden and Mr. Mike K. Norton.
Mr. Riseden, a Licensed Professional Engineer in the State of Texas (No. 100566), has been practicing consulting petroleum engineering at NSAI since 2006 and has over 4 years of prior industry experience. He graduated from Texas A&M University in 2001 with a Bachelor of Science Degree in Petroleum Engineering and from Tulane University in 2005 with a Master of Business Administration Degree.
Mr. Norton, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441), has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology.
Internal Engineers
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. Our technical team meets regularly with representatives of NSAI to review properties and discuss methods and assumptions used in NSAIs preparation of the year-end reserves estimates. The NSAI reserve report is reviewed with representatives of NSAI and our internal technical staff before dissemination of the information. Additionally, members of our management team review the NSAI reserve report with senior reservoir engineering staff and other members of our technical staff.
Martin Dobson, our Director of Reserves and Technology, is the technical person primarily responsible for overseeing the preparation of the Companys reserves estimates by NSAI. He has over 31 years of industry experience, including approximately 20 years of experience in the estimation and evaluation of reserves. His work experience includes well and field reserve estimation for SEC qualification, Acquisition/Disposition and field optimization for gas fields, oil fields, and water floods. He has provided expert witness testimony before the Wyoming Oil and Gas Conservation Commission and is the primary author of multiple SPE papers focused on probabilistic reserve booking and from which key principles were used in the SPEE Monograph 3 of the same subject. He has a Bachelor of Science degree in Biology from Weber State University and a Master of Science degree from Brigham Young University and is a member of the Society of Petroleum Engineers. Our Director of Reserves and Technology reports directly to our Executive Vice President and Chief Operating Officer. Reserves estimates are reviewed and approved by the Director of Reserves and Technology, with final approval by our Executive Vice President and Chief Operating Officer.
Productive Wells
The following table sets forth the number of productive wells in which we owned a working interest at December 31, 2014. Productive wells consist of producing wells and wells capable of producing, including
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natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we have working interests, and net wells are the sum of our fractional working interests owned in gross wells. Each gross well completed in more than one producing zone is counted as a single well. As of December 31, 2014, approximately 86% of our total gross productive wells and 89% of total net productive wells were classified as natural gas wells (in which natural gas is the primary product).
Oil | Natural Gas | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
West Division Business Units: |
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Williston |
209 | 81 | | | 209 | 81 | ||||||||||||||||||
Powder River |
189 | 103 | 179 | 25 | 368 | 128 | ||||||||||||||||||
Greater Green River |
11 | 6 | 447 | 138 | 458 | 144 | ||||||||||||||||||
San Juan |
1 | | 328 | 267 | 329 | 267 | ||||||||||||||||||
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Total West Division |
410 | 190 | 954 | 430 | 1,364 | 620 | ||||||||||||||||||
East Division Business Units: |
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Mid-Continent West |
131 | 43 | 1,244 | 580 | 1,375 | 623 | ||||||||||||||||||
Mid-Continent East |
414 | 102 | 2,223 | 539 | 2,637 | 641 | ||||||||||||||||||
East Texas |
56 | 37 | 1,909 | 1,362 | 1,965 | 1,399 | ||||||||||||||||||
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Total East Division |
601 | 182 | 5,376 | 2,481 | 5,977 | 2,663 | ||||||||||||||||||
Other(1) |
3 | 1 | 10 | 5 | 13 | 6 | ||||||||||||||||||
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Total Productive Wells |
1,014 | 373 | 6,340 | 2,916 | 7,354 | 3,289 | ||||||||||||||||||
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(1) | Other reflects our interests in certain non-core assets located throughout the continental United States. |
Drilling Activities
The table below sets forth the results of the drilling activities for 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, quantities of reserves found or economic value. The information presented below includes our drilling activities with respect to assets divested subsequent to the periods indicated.
Year Ended December 31, 2014 |
Year Ended December 31, 2013 |
Year Ended December 31, 2012 |
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Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Exploratory Wells |
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Productive(1) |
14 | 10 | 11 | 7 | 8 | 6 | ||||||||||||||||||
Dry |
| | | | 1 | 1 | ||||||||||||||||||
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Total Exploratory |
14 | 10 | 11 | 7 | 9 | 7 | ||||||||||||||||||
Development Wells |
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Productive(1) |
176 | 76 | 238 | 71 | 395 | 114 | ||||||||||||||||||
Dry |
5 | 2 | 1 | | 3 | 2 | ||||||||||||||||||
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Total Development |
181 | 78 | 239 | 71 | 398 | 116 | ||||||||||||||||||
Total Wells |
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Productive(1) |
190 | 86 | 249 | 78 | 403 | 120 | ||||||||||||||||||
Dry |
5 | 2 | 1 | | 4 | 3 | ||||||||||||||||||
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Total Development and Exploratory Wells |
195 | 88 | 250 | 78 | 407 | 123 | ||||||||||||||||||
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(1) | Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly with respect to exploratory wells where there is no production history. |
As of December 31, 2014, we had 43 gross (19 net) wells in the process of drilling, completing or waiting on completion and 23 gross (17 net) operated wells in the process of drilling, completing or waiting on completion.
Developed and Undeveloped Acreage
The following table sets forth as of December 31, 2014 our approximate gross and net developed and undeveloped oil and natural gas leasehold and fee mineral acreage. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest.
Developed Leasehold Acreage |
Undeveloped Leasehold Acreage |
Fee Minerals |
Total Acreage |
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(acreage in thousands) | ||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
West Division Business Units: |
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Williston |
143 | 59 | 85 | 39 | 1 | | 229 | 98 | ||||||||||||||||||||||||
Powder River |
258 | 135 | 193 | 157 | 2 | | 453 | 292 | ||||||||||||||||||||||||
Greater Green River |
227 | 120 | 105 | 91 | 1 | | 333 | 211 | ||||||||||||||||||||||||
San Juan |
41 | 29 | 31 | 26 | | | 72 | 55 | ||||||||||||||||||||||||
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Total West Division |
669 | 343 | 414 | 313 | 4 | | 1,087 | 656 | ||||||||||||||||||||||||
East Division Business Units: |
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Mid-Continent West |
326 | 159 | 4 | 4 | 27 | 10 | 357 | 173 | ||||||||||||||||||||||||
Mid-Continent East |
635 | 247 | 33 | 16 | 51 | 15 | 719 | 278 | ||||||||||||||||||||||||
East Texas |
347 | 284 | 23 | 8 | 392 | 68 | 762 | 360 | ||||||||||||||||||||||||
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Total East Division |
1,308 | 690 | 60 | 28 | 470 | 93 | 1,838 | 811 | ||||||||||||||||||||||||
Other(1) |
20 | 7 | 116 | 77 | 12 | 17 | 148 | 101 | ||||||||||||||||||||||||
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Total Acreage |
1,997 | 1,040 | 590 | 418 | 486 | 110 | 3,073 | 1,568 | ||||||||||||||||||||||||
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(1) | Other reflects our interests in certain non-core assets located throughout the continental United States. |
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2014 that will expire during the years indicated if production is not established or if we take no other action to extend the terms of the leases or concessions (other than the payment of delay rentals during the primary term of the applicable lease).
2015 |
2016 | 2017 | ||||||||
Gross |
Net | Gross | Net | Gross | Net | |||||
179,803 |
99,528 | 119,172 | 73,928 | 82,552 | 73,963 |
As of December 31, 2014, less than 1% of our net acres related to proved undeveloped reserves had a lease expiration date preceding the scheduled initial drill date and a portion of such acreage is subject to leasehold extension rights. We intend to exercise such extension rights where applicable, pursue lease renewals and engage in other leasehold management efforts in order to preserve our leasehold interests with respect to such proved undeveloped reserves.
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Production, Revenues and Price History
Oil and natural gas are commodities and, as a result, the prices that we receive for our production can fluctuate widely due to changes in market supply and demand. Commodity prices have historically been volatile, including recently where oil and natural gas prices have declined significantly in the last half of 2014 with continued weakness in 2015. A further decline or sustained depression in oil or natural gas prices could have a material adverse effect on our business, results of operations, financial condition, access to capital and ability to meet our financial commitments and other obligations. For additional information on commodity price volatility and related risks, see Part I, Item 1ARisk Factors.
The following table sets forth information regarding our net production of oil and natural gas and certain price and cost information for each of the periods indicated. The information presented below includes production data with respect to assets divested subsequent to the periods indicated. For additional information on price calculations, see the information set forth in Part II, Item 7Managements Discussion and Analysis of Financial Condition and Results of Operations.
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Production data: |
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Natural gas (Bcf) |
135.2 | 150.9 | 178.8 | |||||||||
Oil (MMBbls) |
5.0 | 5.3 | 6.2 | |||||||||
NGLs (MMBbls) |
4.7 | 4.7 | 4.0 | |||||||||
Combined production (Bcfe)(1) |
193.2 | 210.8 | 240.0 | |||||||||
Average combined daily production (Bcfe/d)(1) |
530 | 578 | 657 | |||||||||
Average sales prices before effects of hedges:(2) |
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Natural gas (Mcf) |
$ | 3.87 | $ | 3.28 | $ | 2.17 | ||||||
Oil (Bbl) |
85.63 | 92.38 | 83.92 | |||||||||
NGL (Bbl) |
31.11 | 32.30 | 35.03 | |||||||||
Mcfe |
5.68 | 5.40 | 4.37 | |||||||||
Average sales prices after effects of realized hedges:(2) |
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Natural gas (Mcf) |
$ | 3.65 | $ | 3.37 | $ | 3.01 | ||||||
Oil (Bbl) |
82.35 | 86.30 | 81.93 | |||||||||
NGL (Bbl) |
31.03 | 32.67 | 35.85 | |||||||||
Mcfe |
5.43 | 5.32 | 4.95 | |||||||||
Average unit cost per Mcfe: |
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Production costs: |
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Lease operating expenses |
$ | 1.09 | $ | 0.93 | $ | 0.93 | ||||||
Production taxes |
0.41 | 0.36 | 0.34 | |||||||||
Total |
$ | 1.50 | $ | 1.29 | $ | 1.27 | ||||||
Depreciation, depletion and amortization |
2.48 | 2.65 | 2.84 | |||||||||
General and administrative expenses |
0.91 | 0.62 | 0.63 |
(1) | Oil is converted to Mcfe using the industry standard conversion rate of one barrel of oil to six thousand cubic feet of natural gas. |
(2) | Average prices shown in the table reflect prices both before and after the effects of our realized economic commodity hedging transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivatives. |
Our Oil and Natural Gas Properties
We operate our business and properties under two major divisions, which we refer to as our West Division and our East Division. As of December 31, 2014 and as of all applicable dates presented, we did not have any individual
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fields containing 15% or more of our total estimated proved reserves. Our historical daily production volumes for each business unit in our West and East divisions are summarized in Part II, Item 7Managements Discussion and Analysis of Financial Condition and Results of Operations.
West Division
Our West Division is primarily situated in the Rocky Mountains region and encompasses several major basins. Our West Division accounted for approximately 30% of our proved reserves as of December 31, 2014. As of December 31, 2014, we had approximately 656,000 net acres in our West Division, of which 52% was held by production. As of December 31, 2014, we had interests in approximately 1,364 gross (620 net) productive wells in our West Division and operated approximately 51% of these wells and approximately 89% of our net production. Our West Division is divided into four distinct business units, which are primarily focused on the Williston, Powder River, Greater Green River and San Juan basins, respectively.
Williston Business Unit. Our Williston business unit consists of our assets in North Dakota, Montana and South Dakota. As of December 31, 2014, our Williston business unit had approximately 98,000 net acres, including approximately 67,000 net acres in North Dakota, which represents our core operating position in the Williston Basin. We operated approximately 29,000 net acres, or approximately 43% of our core Williston Basin position as of December 31, 2014. As of December 31, 2014, we had approximately 209 gross (81 net) productive wells in the Williston business unit. The Williston Basin produces from numerous hydrocarbon bearing horizons, including the Madison, Bakken, Three Forks and Red River formations. Within our operating area, we primarily produce from the Middle Bakken and Three Forks formations. During 2014, our Williston business unit completed 18 gross (eight net) operated wells.
Powder River Business Unit. Our Powder River business unit primarily includes our properties in the Powder River Basin in Wyoming as well as certain non-core assets in Eastern Colorado. We had approximately 292,000 net acres and approximately 368 gross (128 net) productive wells in the Powder River business unit as of December 31, 2014. Our properties in the Powder River Basin have exposure to various oil producing horizons, including the Parkman, Sussex, Shannon, Niobrara, Frontier and Mowry formations. Within our operating area, we have primarily focused on the Shannon and Sussex formations. Our Powder River business unit completed 25 gross (20 net) operated horizontal wells during 2014.
Greater Green River Business Unit. As of December 31, 2014, we had approximately 211,000 net acres and approximately 458 gross (144 net) productive wells in the Greater Green River business unit, which includes our Greater Green River Basin properties in Wyoming and certain other assets located in Eastern Utah and Western Colorado. Our properties in the Greater Green River business unit include mature, producing assets in the Wamsutter Field as well a position in the Cepo Field, where we have exposure to the liquids-rich Fort Union reservoir. During 2014, our Greater Green River business unit completed five gross (four net) operated wells.
San Juan Business Unit. Our San Juan business unit consists of our assets in Southern Colorado and Northwestern New Mexico in the San Juan Basin as well as non-core properties in Southeastern Utah. We had approximately 55,000 net acres and approximately 329 gross (267 net) productive wells in our San Juan business unit as of December 31, 2014. Our San Juan business unit operates a large, mature production base in the San Juan Basin that produces primarily from the Fruitland coal formation. During 2014, our San Juan business unit completed four gross (four net) operated wells.
East Division
Our East Division primarily consists of our assets in the Mid-Continent and East Texas regions and includes several major basins, including the Anadarko and East Texas basins. Our East Division accounted for approximately 70% of our proved reserves as of December 31, 2014. As of December 31, 2014, we had 811,000 net acres in our East Division, of which 97% was held by production. As of December 31, 2014, we had interests in approximately 5,977 gross (2,663 net) productive wells in our East Division and operated 46% of these wells
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and 76% of our net production. Our East Division is divided into three distinct business units, which are primarily focused on the Mid-Continent West, the Mid-Continent East and the East Texas regions, respectively.
Mid-Continent West Business Unit. Our Mid-Continent West business unit includes our assets in the Texas and Oklahoma Panhandles as well as Kansas. As of December 31, 2014, we held approximately 173,000 net acres and approximately 1,375 gross (623 net) productive wells in the Mid-Continent West business unit. Our properties in the Mid-Continent West business unit have exposure to the Cleveland, Granite Wash and Douglas formations. During 2014, our Mid-Continent West business unit completed 13 gross (10 net) operated wells.
Mid-Continent East Business Unit. Our Mid-Continent East business unit includes our assets in the Anadarko Basin in Central and Western Oklahoma (excluding the Oklahoma Panhandle region) as well as our properties in Eastern Oklahoma and Northern Arkansas. As of December 31, 2014, we had approximately 278,000 net acres and approximately 2,637 gross (641 net) productive wells in the Mid-Continent East business unit. There are numerous hydrocarbon bearing formations across our Anadarko Basin properties in the Mid-Continent East business unit, including the Marmaton, Mississippi Solid, Cana Woodford and Tonkawa formations. In March 2015, we divested a substantial portion of our Arkoma Basin assets in Eastern Oklahoma for approximately $48.0 million, subject to customary post-closing purchase price adjustments. During 2014, our Mid-Continent East business unit completed 17 gross (13 net) operated wells.
East Texas Business Unit. Our East Texas business unit had 360,000 net acres and approximately 1,965 gross (1,399 net) productive wells as of December 31, 2014 and is comprised of our properties in East Texas, Northern Louisiana, Southern Arkansas and the Permian Basin. Our East Texas business unit includes significant positions in the Cotton Valley Sand and Haynesville Shale formations. In December 2014, we completed the acquisition of approximately 37,000 net acres in East Texas for approximately $57.6 million, subject to customary post-closing purchase price adjustments, to increase our existing Cotton Valley position in our East Texas business unit. During 2014, our East Texas business unit completed 25 gross (21 net) operated wells.
Other
In addition to the properties described above, we also own interests in certain non-core assets located throughout the continental United States. As of December 31, 2014, we held approximately 101,000 net acres in these non-core areas, and these assets accounted for less than one percent of our total production during the year ended December 31, 2014. We had approximately 13 gross (6 net) productive wells in these non-core areas as of December 31, 2014.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct a limited review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, however, we conduct a more thorough title examination and perform curative work with respect to material defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing or resolving such title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on the property. In addition, prior to completing an acquisition of producing oil and natural gas leases, we generally perform title reviews on the most significant leases, and depending on the materiality of properties, we may obtain an attorneys title opinion or review previously obtained title opinions. Based on the foregoing, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our oil and natural gas properties are subject to customary royalty and other interests, liens under the credit agreements governing the RBL Revolver and Second Lien Term Loan, liens for current taxes and other burdens which we believe do not materially interfere with the use of, or affect our carrying value of, the properties.
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Office Facilities
In addition to our oil and natural gas properties discussed above, we lease corporate office space in Tulsa, Oklahoma, Denver, Colorado and Houston, Texas, and we also maintain a number of field office locations. We believe that our existing office facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
Risk Management
We use derivative financial instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices by reducing the risk of price volatility and the effect it could have on our operations and our ability to finance our capital budget and operations. Our decision on the quantity and price at which we choose to hedge our production is based on our view of existing and forecasted oil, natural gas and natural gas liquids production volumes, planned drilling projects and current and future market conditions. While there are many different types of derivatives available, we typically use fixed price swaps, collars (put and call options) and occasionally basis swap agreements to attempt to manage price risk more effectively. The swaps call for payments to, or receipts from, counterparties based on whether the market price of oil, natural gas or natural gas liquids for the period is greater or less than the fixed price established for that period when the swap is put in place. The collar arrangements are put and call options used to establish a fixed price floor and a fixed price ceiling for a specified period of time. The purchaser of a put option will collect payment when the market price settles lower than the put exercise prices and the purchaser of a call option will collect payment when the market price settles greater than the call exercise price. For additional information on our derivative financial instruments, see in Part II, Item 7Managements Discussion and Analysis of Financial Condition and Results of Operations and Note 8 to our audited consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that possess and employ financial, technical and personnel resources that are substantially greater than ours. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Such competition can also drive up the costs to acquire oil and natural gas leases, properties and prospects in areas where we are already conducting business and operations.
In addition, because of our significant indebtedness and debt service costs, many of our competitors have a greater ability than us to continue exploration and development activities during periods of low oil and natural gas market prices. The more favorable capital structure of these companies may also give them better access to capital and on better terms, which could give such companies an advantage in the financing and execution of acquisitions and their drilling programs.
There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by federal, state or local governments. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position.
15
Marketing and Significant Customers
We market the oil and natural gas production from properties we operate for both our account and the account of many of the other working interest owners in these properties. We sell our production to a variety of purchasers under market-based contracts with terms ranging from one day to eighteen years.
During the year ended December 31, 2014, we had no purchasers that accounted for more than 10% of our total crude oil and natural gas revenues. We do not believe that the loss of any of the customers or entities to which we have exposure would result in a material adverse effect on our ability to market our oil and natural gas production.
Delivery Commitments
A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. As of December 31, 2014, we were committed to deliver the following fixed quantities of production.
Total | Less than 1 Year |
1-3 Years |
3-5 Years |
More than 5 Years |
||||||||||||||||
Natural Gas (Bcf) |
20.3 | 20.3 | | | | |||||||||||||||
Oil (MMbbl) |
| | | | |
We expect to fulfill our delivery commitments with production from our proved developed reserves and the production of others who market with us. However, should these sources not be sufficient to satisfy our delivery commitments, we can and may use spot market purchases to fulfill these commitments.
In addition, we have entered into marketing agreements with various midstream service providers and pipeline carriers to facilitate the delivery of our production to market. Certain of these agreements include firm transportation or throughput commitments. Firm transportation commitments require us to pay reservation charges for specified quantities regardless of the amount of pipeline capacity used, and throughput commitments require us to deliver specified volumes or pay certain fees for any shortfalls. For additional information on our obligations under such arrangements, see Part II, Item 7Managements Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesContractual Obligations.
Seasonality of Business
Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling and production activities, disrupting our overall business plans. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
In addition, current lease terms, permit conditions and stipulations and other governmental regulatory conditions restrict drilling operations and certain other activities during certain times of the year on a significant portion of our properties in the Greater Green River and Powder River basins due to wildlife activity and/or habitat. We have worked with federal and state officials in Wyoming to obtain approval for limited winter-drilling activities on these assets and have developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of our activities on wildlife and wildlife habitat.
Governmental Regulation
Regulation of Production of Oil and Natural Gas
Our operations are substantially affected by federal, state, tribal, local and other laws, regulations and agency actions and rule making. In particular, natural gas production and related operations are, or have been,
16
subject to price controls, taxes and numerous other laws, regulations and agency actions. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, drilling or operating bonds, reports concerning operations, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of wells. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction.
Our operations are also subject to various oil and natural gas conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, the unitization or pooling of oil or natural gas properties and prohibitions or limits on the venting or flaring of natural gas. In addition, these regulations may establish maximum rates of production from oil and natural gas wells and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells, the vertical deviation of such wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions or expansions in well spacing. Furthermore, some states have become concerned that the disposal of produced water could under certain circumstances contribute to seismicity, and therefore, they have adopted or are considering adopting additional regulations governing such disposal.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. In addition, such laws and regulations are frequently amended or reinterpreted and, as a result, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by federal, state and local governments, courts and agencies. We cannot predict when or whether any such proposals may become effective.
We believe we are in material compliance with currently applicable laws and regulations and that continued material compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily the Federal Energy Regulatory Commission (FERC). FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services.
In the past, the federal government regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at competitive market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act (NGPA) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (the NGA) and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate
17
transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.
Beginning in 1992, FERC issued a series of orders to implement its open access policies. As a result, the interstate pipelines traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERCs orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
The Energy Policy Act of 2005 (EP Act 2005) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EP Act 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act 2005 provides FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases FERCs civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of EP Act 2005, and subsequently denied rehearing. The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted in connection with gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERCs NGA enforcement authority.
On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 or such other time as directed by FERC each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERCs policy statement on price reporting.
On November 20, 2008, FERC issued Order 720, a final rule on the daily scheduled flow and capacity posting requirements. Under Order 720, major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtus of gas over the previous three calendar years, are required to post daily certain information regarding the pipelines capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day and may also require posting or reporting of rates associated with services on those pipelines. Requests for clarification and rehearing of Order 720 have been filed at FERC and a decision on those requests is pending.
We cannot accurately predict whether FERCs actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently
18
established by FERC will continue. However, we currently have no reason to believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipelines status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of on-going litigation, so the classification or reclassification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or the U.S. Congress.
Our sales of natural gas are also subject to requirements under the Commodity Exchange Act (CEA) and regulations promulgated thereunder by the Commodity Futures Trading Commission (CFTC). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of state regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis should not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines and certain interstate pipelines, and we cannot predict what future action FERC will take, if any. We currently have no reason to believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.
Environmental Matters
Our operations are subject to extensive and increasingly stringent federal, state and local laws, as well as agency actions and rule making, pertaining to the protection of the environment and human health and safety. These include requirements governing the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), or otherwise relating to pollution or protection of the environment, natural resources, or human health and safety. Wellbore integrity regulations have also been enacted and are being considered by a number of regulatory bodies. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (EPA) and state environmental regulatory authorities, have the authority to prescribe and implement environmental, health and
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safety regulations governing various aspects of oil and natural gas production. We must take into account the timing and cost of complying with, and in many cases applying for permits under, such laws and regulations in planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities, including gathering, transportation, and waste treatment, storage and disposal facilities. If we fail to comply with these laws and regulations, we could be assessed administrative, civil and criminal penalties, as well as be issued injunctions requiring remediation or limiting or prohibiting our activities.
Environmental regulatory programs typically regulate the handling and disposal of drilling and production materials and wastes, human health and safety practices, and the protection of land, water, air and various wildlife, including threatened and endangered species. We may be required to obtain permits for, among other things, air emissions, the construction and operation of surface pits to contain drilling muds and other wastes resulting from drilling and production activities, the construction and operation of underground injection wells to use for disposal of produced water and other oilfield wastes, and the construction of facilities on Indian lands or in environmentally sensitive areas such as wetlands and wilderness areas. Many factors, including public perception, government policy and agency funding can materially impact the ability to secure environmental construction or operations permits.
We have made and will continue to make expenditures to comply with environmental, health and safety laws and regulations. These are necessary business costs in the oil and natural gas industry. We believe that we are in material compliance with currently applicable environmental, health and safety laws and regulations and that the cost of maintaining material compliance with these existing regulations will not have a material adverse effect on our business, financial position and results of operations. It is possible that developments, such as the imposition of stricter and more comprehensive environmental, health and safety laws and regulations or changes in the way existing requirements are interpreted or enforced, as well as the discovery of past non-compliance with environmental laws and regulations, the occurrence of currently unforeseen environmental incidents or receipt of claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities, including civil and criminal penalties and remediation costs, and could adversely affect our ability to continue our business as presently conducted.
Solid and Hazardous Waste
Federal, state and local laws may require us to remove or remediate disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with laws or otherwise, to suspend or cease operations at contaminated areas, or to perform remedial well plugging operations or response actions to reduce the risk of future contamination or threats to public health or the environment. Federal laws, including the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws may impose strict, and in certain cases joint and several, liability, without regard to fault, on specified potentially responsible parties, including current or prior owners or operators of contaminated sites or parties that arranged for the disposal of hazardous substances at contaminated sites, for the costs of investigating and cleaning up hazardous substances, as well as liability for damages to natural resources. Other federal and state laws, in particular the federal Resource Conservation and Recovery Act (RCRA), regulate hazardous and non-hazardous wastes. Under a longstanding legal framework, certain wastes generated by our oil and natural gas operations are not currently subject to RCRA regulations governing hazardous wastes, though they are generally subject to RCRA regulations governing non-hazardous wastes and may be regulated under other federal laws. Many states also have specific regulations governing wastes generated by oil and natural gas operations. These wastes may in the future be designated as hazardous wastes under RCRA or may otherwise become subject to more rigorous and costly compliance and disposal requirements.
From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. In some cases we have acquired properties or businesses with a history of on-site contamination. In addition, some of our owned and leased properties have been used for oil and natural gas exploration, production and related activities for a number of years, often by third parties not under our control. We and/or other owners
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and operators of these facilities may have generated or disposed of wastes that polluted the soil, surface water or groundwater at our facilities and adjacent properties. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance. Under applicable federal, state and local laws, we have been and continue to be required to address contamination at a number of locations and, to the extent new spills or releases occur or previously unknown contamination is discovered, we may be required to do so again in the future. We are currently addressing contamination at several locations, in some instances in consultation with regulatory authorities and also have received potentially responsible party notices alleging potential liability for cleanup of a certain off-site waste disposal site which has been primarily covered by a site specific insurance policy. While we do not anticipate at this time that these matters or any other contamination or remediation matters are likely to have a material adverse effect on our business, financial position or results of operations, we cannot predict with certainty whether the occurrence of new spills or releases, or the discovery of previously unknown contamination, might result in significant future liabilities.
In addition, we have been subject to lawsuits brought by third parties alleging damages as a result of our operations, and such suits are currently pending against us regarding several locations. While we do not anticipate at this time that resolution of any of these lawsuits is likely to have a material adverse effect on our business, financial position or results of operations, we cannot predict with certainty how liabilities will be allocated in pending matters, or whether new claims may be made against us as a result of the occurrence of new spills or releases, or the discovery of previously unknown contamination.
Groundwater Protection
It is customary in the oil and natural gas industry to manage, store and dispose of produced water and drilling wastes in pits and underground injection wells, and to use enhanced recovery techniques in unconventional and tight oil and natural gas formations, and we or our operators or contractors use these techniques at some of our locations. Should such techniques result in groundwater contamination, we could be subject to fines, penalties and remediation costs under federal laws, including the Safe Drinking Water Act (SDWA), and state laws. In addition, landowners and other parties may file claims for personal injury, property and natural resource damages and the cost of providing alternative water supplies.
Most of our recent drilling operations have been in tight and unconventional oil and natural gas formations, which are drilled using hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of bills proposed in the U.S. Congress have asserted that chemicals used in the fracturing process may be adversely impacting drinking water supplies. Proposed federal legislation would amend the federal SDWA to repeal the general exemption for hydraulic fracturing from the SDWA, thus requiring the permitting of each and every hydraulic fracturing project, and require the disclosure of chemicals used in the hydraulic fracturing process. This could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing groundwater or causing other damage. Such bills, if adopted, could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
There have been several recent federal initiatives related to hydraulic fracturing. In April 2012, the White House issued an executive order creating a multi-agency task force to coordinate federal oversight of hydraulic fracturing. In February 2014, EPA issued an interpretive memorandum to clarify underground injection control (UIC) requirements under the SDWA for use of diesel fuels in hydraulic fracturing, and a technical guidance containing recommendations for EPA permit writers to consider in implementing these UIC requirements. These documents clarified that any owner or operator who injects diesel fuels in hydraulic fracturing for oil or gas extraction must obtain a UIC permit before injection. EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2015. In
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addition, the federal Bureau of Land Management proposed and is in the process of reconsidering regulations requiring disclosure of chemicals used in the hydraulic fracturing process both before and after any drilling on federal public land.
Other EPA initiatives have focused on studies related to hydraulic fracturings potential impact on drinking water. At the request of the U.S. Congress, EPA is undertaking a national study to understand the potential impact of hydraulic fracturing on drinking water resources. The study has included a review of published literature, analysis of existing data, scenario evaluation and modeling, laboratory studies, and case studies. EPA issued a progress report in December 2012 detailing the steps being undertaken in the study, and expects to release a final draft report for peer review and comment in 2015. In December 2011, EPA published a draft report finding that hydraulic fracturing is a likely cause of drinking water contamination in the vicinity of Pavillion, Wyoming; however, in September 2013, EPA announced that it does not plan to finalize or seek peer review of the report, and that it will continue to support the State of Wyoming in the States investigation of the groundwater contamination. EPAs testing results were confirmed by a second round of well tests in October 2012; however, the conclusions to be drawn from the testing results remain controversial and the findings relate only to wellbore integrity for the specific shallow gas wells that were a part of the States investigation. Findings such as this could increase public pressure on governmental authorities to implement new regulations regarding hydraulic fracturing.
Many states and cities have adopted, or are considering, regulations regarding hydraulic fracturing, including requiring the disclosure of chemicals injected during hydraulic fracturing. Vermont banned hydraulic fracturing in the state in 2012 and certain states such as New York and New Jersey issued moratoriums on hydraulic fracturing while they considered studies of and regulations regarding hydraulic fracturing, although New York announced in December 2014 that it will move to ban hydraulic fracturing in the state in 2015 and New Jerseys moratorium expired in 2013. In some areas hydraulic fracturing has also been the subject of local ordinances attempting to ban or limit the practice; court challenges to such ordinances have had varied outcomes to date. If new state or local laws or regulations are adopted that significantly increase the risk of legal challenges to, or restrict the use of, hydraulic fracturing, such legal requirements could make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
We voluntarily participate in FracFocus, a national publicly accessible Internet-based registry developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. This registry, located at www.fracfocus.org, provides our industry with an avenue to voluntarily disclose additives used in the hydraulic fracturing process. The information included on or accessible through this website is not incorporated by reference in this report.
Based on increased regulation and attention given to the hydraulic fracturing process from federal, state and various local governments and increased public scrutiny, greater opposition and litigation toward oil and natural gas production utilizing hydraulic fracturing techniques is anticipated. Additional legislation or regulation could lead to operational delays, increased operating costs or a decrease in completion of new oil and natural gas wells all of which could adversely affect our financial position, operations and cash flows.
Air Emissions
Our operations produce air emissions through the use of equipment such as compressor engines, condensate and produced water tanks, dehydrators, and heater treaters, and the production of fugitive and loading emissions and flares. The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through requirements such as New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP). We, and/or contractors that we employ, are required to obtain federal or state air permits prior to operating certain equipment, and must comply with limits on the emissions of certain pollutants. If we fail to comply with such requirements, we may be subject to administrative, civil and criminal penalties. On April 17, 2012, EPA issued a final rule setting forth new NSPS and NESHAP standards for the oil
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and natural gas sector. The new rule will be fully implemented in 2015. We are continuing to evaluate the effect of this rule on our business, but we do not expect these requirements to materially adversely affect our business, financial condition or results of operations. Because of the subjectivity in the assumptions underlying our estimated compliance costs with respect to this rule, however, the costs to ultimately comply with the rule may vary significantly from our estimates, which could materially adversely affect our business, financial condition and results of operations.
Climate Change and Greenhouse Gas Regulation
Global climate change continues to attract considerable public, scientific and regulatory attention, and greenhouse gas (GHG) emission regulation is becoming more stringent. EPA has taken a number of steps towards regulating GHG emissions under the Clean Air Act, including its Mandatory Reporting of Greenhouse Gases Rule published in October 2009, and expanded in November 2010 to include onshore oil and natural gas production activities, its endangerment and cause or contribute findings under Section 202(a) of the Clean Air Act published in December 2009, and its so-called Tailoring Rule concerning regulation of large emitters of GHGs under the Clean Air Acts Prevention of Significant Deterioration (PSD) Program and Title V program issued in May 2010, which has been subject to litigation. These and future EPA rulemakings regarding GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.
Under the Mandatory Reporting of Greenhouse Gases Rule, we are currently required to report annual GHG emissions from some of our operations. For reporting year 2010, we were required to report emissions from general combustion sources with GHG emissions greater than 25,000 metric tons CO2 equivalent, and only three of our large compressor stations triggered this requirement. For reporting year 2011 and thereafter, we became subject to additional GHG reporting requirements applicable to the oil and natural gas sector, which require estimation of routine and episodic releases of GHGs (primarily methane) from a wide range of equipment such as gas-driven pneumatic equipment, well venting for work overs and completions, storage tanks, dehydrators and compressors (including fugitive leaks from valves, flanges, etc.) across our entire system. These reporting requirements are being phased in over a number of years and, although we cannot determine with accuracy what our additional costs will be to implement the new requirements, we do not expect these new requirements to materially adversely affect our business, financial condition or results of operations.
Additional GHG emission-related requirements that are in various stages of development may also affect our operations. In response to the U.S. Presidents June 2013 Climate Action Plan, EPA issued a Clean Power Plan designed to cut GHG emissions from existing fossil-fuel fired power plants in June 2014, proposed standards for modified and reconstructed fossil-fuel fired power plants in June 2014, and issued a revised proposal with standards for new fossil fuel-fired plants in September 2013. In March 2014, the Obama administration announced a strategy to reduce methane emissions, which was followed by the administrations January 2015 announcement of a goal to cut methane emissions from the oil and gas sector by 40-45 percent from 2012 levels by 2025. EPA expects to issue a proposed rule in the summer of 2015 and final rule in 2016 to reduce methane emissions. In addition to EPA initiatives, the U.S. Congress has considered legislation that would establish a nationwide cap-and-trade system for GHGs. In addition, a number of states have begun taking action on their own or as part of a multi-state program to control and/or reduce GHG emissions. If enacted, such laws and regulations could require us to modify existing, or obtain new, permits, implement additional pollution control technology, curtail operations or increase significantly our operating costs.
A number of states have begun taking action on their own or as part of a multi-state program to control and/or reduce GHG emissions. For example, California enacted the Global Warming Solutions Act of 2006 (AB 32), which led to the adoption of GHG reporting requirements in 2008 and implementation of a broad-based GHG cap-and-trade program beginning in 2013 (the program will expand in 2015). In addition, nine Northeastern and Middle Atlantic states participating in the Regional Greenhouse Gas Initiative have capped GHG emissions for fossil-fuel powered electrical generation units with a capacity of 25 or more megawatts beginning in 2014, with the cap declining annually between 2015 and 2020.
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Regulation of GHG emissions could also result in reduced demand for our products, as oil and natural gas consumers seek to reduce their own GHG emissions. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could materially adversely affect our business, reputation, operating performance and product demand. In addition, to the extent climate change results in more severe weather and significant physical effects, such as increased frequency and severity of storms, floods, and droughts, our own or our customers operations may be disrupted, which could result in a decrease in our available product or reduce our customers demand for products.
Threatened and Endangered Species
Our operations may affect wildlife, including threatened and endangered species. Current lease terms, permit conditions and stipulations and other governmental regulatory conditions restrict drilling operations and certain other activities during certain times of the year on a significant portion of our properties in the Greater Green River and Powder River basins due to wildlife activity and/or habitat. In addition, the U.S. Fish and Wildlife Service recently announced its decision to list the lesser prairie chicken as threatened under the U.S. Endangered Species Act. The lesser prairie chickens habitat overlaps certain of our properties in Western Oklahoma and the Texas Panhandle. We elected to participate in a related U.S. Fish and Wildlife endorsed conservation plan for the lessor prairie chicken that could restrict our operations and result in additional costs with respect to the affected areas. Under a 2011 settlement, the U.S. Fish and Wildlife Service is required to make a determination on the listing of more than 250 species as endangered or threatened over the next several years. The presence of other wildlife, wildlife habitats or plants, including species that are or will be protected under the U.S. Endangered Species Act, could result in additional restrictions on our ability to access and/or operate these and other properties, including with respect to our other core positions, which could materially adversely affect our business, results of operations and financial condition.
Related Insurance
We maintain insurance against claims arising from releases or contamination associated with our exploration and production activities. This insurance includes general liability, environmental, umbrella, and site specific policies. However, this insurance is generally limited to activities that occur on or result from a covered location, such as wellsites and certain key facilities, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event or discovery of conditions that are not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.
Employees
As of December 31, 2014, we had 997 employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees.
In March 2015, we announced a workforce reduction of approximately 30% of our employees.
Address, Internet Website and Availability of Public Filings
Our principal executive offices are located at Samson Plaza, Two West Second Street, Tulsa, Oklahoma 74114, and our telephone number is (918) 591-1791. Our website is located at www.samson.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to the Exchange Act are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the SEC. Information on or accessible through our website does not constitute part of this report and is not incorporated into it.
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ITEM 1A. | RISK FACTORS |
You should carefully consider the risk factors set forth below. Any of the following risks may materially adversely affect our business, results of operations and financial condition. The risks and uncertainties described below are not the only risks and uncertainties that we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also materially adversely affect our business, results of operations and financial condition. In such a case, you may lose all or part of your original investment. The risks discussed below also include forward-looking statements, and our actual results may differ substantially from those discussed in these forward-looking statements. See Cautionary Statement Regarding Forward-Looking Statements in this report.
Our substantial indebtedness and the fact that a significant portion of our cash flow is used to make interest payments could adversely affect our ability to raise additional capital to fund our operations, increase our vulnerability to changes in the economy or our industry, including commodity price volatility, and prevent us from making debt service payments.
We are a highly leveraged company with significant debt service costs. As of December 31, 2014, we had total indebtedness of $3.9 billion (excluding the Cumulative Preferred Stock). Our substantial indebtedness and debt service costs could:
| make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations of any of our debt agreements, including restrictive covenants, could result in an event of default under those arrangements; |
| limit our ability to obtain additional financing to fund future working capital, capital expenditures for both operated and outside operated properties, acquisitions, development activities or other general corporate requirements; |
| require a substantial portion of our cash flows to be dedicated to debt service payments instead of other purposes, thereby reducing the amount of cash flows available for working capital, capital expenditures, investments or acquisitions and other general corporate purposes; |
| increase our vulnerability to adverse changes in general economic, industry and competitive conditions, including decreased commodity prices or increased interest rates; |
| reduce our ability to borrow additional funds if we do not replace our reserves since the collateral value of our assets is based, in part, on the value of our proved reserves; and |
| limit our flexibility in planning for, or reacting to, changes in our business or industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from, including exploring for, acquiring and developing oil and natural gas properties. |
Any of the foregoing could materially adversely affect our business, results of operations, financial condition, access to capital and ability to satisfy our outstanding debt obligations.
We may not be able to generate or obtain sufficient cash to service all of our indebtedness, and we may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
We may be unable to generate sufficient cash flow from operations or to obtain alternative sources of financing in an amount sufficient to fund our liquidity needs. Our operating cash inflows are typically used for capital expenditures, operating expenses, debt service costs and working capital needs. Since the Acquisition, the amount of these obligations have exceeded our operating cash flows, thereby requiring us to rely on debt financing and asset sales to fund any shortfalls.
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We do not expect our cash flow from operations to be sufficient to repay our indebtedness in the long term, and we expect to ultimately seek a restructuring, amendment or refinancing of our debt. We cannot predict at this time whether we will be able to secure any such transaction, even if market conditions and our financial condition improve between now and then. Even if such transactions were available to us, we may not find them suitable or at comparable interest rates to the indebtedness being refinanced or restructured and they may require us to comply with more onerous covenants, which could further restrict our operations. In addition, the terms of existing or future debt agreements may restrict us from securing such a transaction on terms that are available to us at that time. We also may be required to dispose of material assets to meet our debt service and other obligations. We may not be able to consummate such dispositions on commercially favorable terms or at all, and any disposition of assets could negatively impact our future performance by reducing our production and reserves. Furthermore, any proceeds that we could realize from any such dispositions may not be adequate to meet our debt service obligations then due. We could also be required to reorganize the Company in its entirety. Neither the Principal Stockholders nor any of their respective affiliates has any continuing obligation to provide us with debt or equity financing.
Moreover, our business requires substantial capital expenditures to explore for and develop oil and natural gas properties. As a result of our high-level of indebtedness and the recent volatility in commodity prices, we have ceased drilling activities and have significantly reduced our planned capital spending on drilling and completion activities in 2015 as compared to prior years. This reduction in capital expenditures will curtail the development of our properties, which in turn will lead to a decline in our production and reserves. A decline in our production and reserves may further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operations and the value of our assets.
We have substantial debt service obligations over the next several months. In addition to monthly interest payments associated with borrowings outstanding under our RBL Revolver, we are required to pay approximately $110.0 million in interest on our Senior Notes on each February 15 and August 15 and approximately $12.5 million in interest on our Second Lien Term Loan at the end of each fiscal quarter. We will continue to evaluate whether to make such payments in light of our liquidity constraints and ongoing negotiations regarding various strategic initiatives. Any failure to make future interest payments on our Senior Notes or to cure a default within the applicable 30-day grace period may result in an Event of Default under the indenture governing the Senior Notes, which would entitle holders of at least 30% of the aggregate principal amount outstanding to immediately accelerate the Senior Notes and declare all outstanding principal and interest to be due and payable. If we cannot make payments on our other indebtedness, the lenders under the RBL Revolver could terminate their commitments to loan money, our secured lenders (including the lenders under the RBL Revolver and the Second Lien Term Loan) could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation. As a result, if we are unable to service our debt obligations generally, and if we are unable to successfully refinance our debt obligations or effect a similar alternative transaction, we cannot assure you that the Company will continue in its current state or that your investment in the Company will retain any value.
Despite our level of indebtedness, we may still be able to incur substantially more indebtedness. This could further exacerbate the risks to our financial condition described above and prevent us from fulfilling our debt obligations.
We may be able to incur significant additional indebtedness in the future. Our debt agreements contain restrictions on the incurrence of additional indebtedness, which are subject to a number of qualifications and exceptions, and the additional indebtedness incurred in compliance with these restrictions could be substantial. Any increase in our level of indebtedness could further exacerbate the risks to our financial condition described above, including by increasing the cash requirement needed to support additional debt service costs attributable to any new debt.
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Due to reduced commodity prices and lower operating cash flows, coupled with substantial interest payments, there is substantial doubt about our ability to maintain adequate liquidity through 2015.
During the second half of 2014, NYMEX-WTI oil prices fell from in excess of $100 per Bbl to below $50 per Bbl, the lowest price since 2009. Our operating cash flows for 2014 declined by $201.1 million to $487.6 million, as compared to the cash flows for 2013. We have experienced continued weakness in product pricing in the first quarter of 2015. These events have caused a reduction in our available liquidity and we may not have the ability to generate sufficient cash flows from operations and, therefore, sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. We are currently evaluating strategic alternatives to address our liquidity issues and high debt levels. These efforts include, among others, a focus on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure you that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows. We are currently reviewing our alternatives and may adopt other strategies that may include actions such as a refinancing or restructuring of our indebtedness or capital structure, reducing or delaying capital investments or seeking to raise additional capital through debt or equity financing. We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Furthermore, we cannot assure you that any of our strategies will yield sufficient funds to meet our working capital or other liquidity needs, including for payments of interest and principal on our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations.
Due to uncertainty about our liquidity and our ability to comply with all of our restrictive covenants contained in our agreements governing our various credit facilities, there is substantial doubt about our ability to continue as a going concern for the next twelve months.
Absent completion of certain actions that are not solely within our control, we do not expect our forecasted cash and credit availability to be sufficient to meet our commitments as they come due over the next twelve months nor do we expect to remain in compliance with all of the restrictive covenants contained in our credit agreements throughout 2015 unless those requirements are amended further. As a result, there is substantial doubt we can continue as a going concern. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with our ability to meet our obligations as they come due. In order to continue as a going concern, we will need to (i) sell additional assets, (ii) restructure our debt, (iii) minimize our capital expenditures, (iv) obtain waivers or amendments from our lenders, (v) effectively manage our expenses and working capital and/or (vi) improve our cash flows from operations. Completion of the foregoing actions is not solely within our control and we may be unable to successfully complete one or all of these actions. Our consolidated financial statements have been prepared on the basis of a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. If we become unable to continue as a going concern, we will need to liquidate our assets and we might receive significantly less than the values at which they are carried in our consolidated financial statements. See Note 1, (Industry conditions, liquidity, managements plans, and going concern) to our consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
Oil and natural gas prices are volatile. Low oil or natural gas prices could materially adversely affect our business, results of operations and financial condition.
Our revenues, profitability and the value of our properties substantially depend on prevailing oil and natural gas prices. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to changes in supply and demand. Oil and natural gas prices historically have been volatile, and are likely to continue to be volatile in the future, especially given current economic and geopolitical conditions. During the second half of 2014, prompt month NYMEX-WTI oil prices fell from in excess of $100 per Bbl to the
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mid $50s, the lowest price since 2009 when prices briefly fell below $35 per Bbl. Thus far in 2015, commodity prices have continued to be depressed, with prompt month NYMEX natural gas prices ranging from approximately $2.60 per MMbtu to $3.20 per MMbtu and prompt month NYMEX-WTI oil prices ranging from approximately $44 per Bbl to $53 per Bbl through March 16, 2015. We expect such volatility to continue in the future. The prices for oil and natural gas are subject to a variety of factors beyond our control, such as:
| domestic and global economic conditions impacting the supply and demand of oil and natural gas; |
| uncertainty in capital and commodities markets; |
| the price and quantity of foreign imports; |
| domestic and global political conditions, particularly in oil and natural gas producing countries or regions, such as the Middle East, Russia, the North Sea, Africa and South America; |
| the ability of members of the Organization of Petroleum Exporting Countries and other producing countries to agree upon and maintain oil prices and production levels; |
| the level of consumer product demand, including in emerging markets, such as China; |
| weather conditions, force majeure events such as earthquakes and nuclear meltdowns; |
| technological advances affecting energy consumption and the development of oil and natural gas reserves; |
| domestic and foreign governmental regulations and taxes, including administrative or agency actions and policies; |
| commodity processing, gathering and transportation cost and availability, and the availability of refining capacity; |
| the price and availability of alternative fuels and energy; |
| the strengthening and weakening of the U.S dollar relative to other currencies; and |
| variations between product prices at sales points and applicable index prices. |
Oil and natural gas prices affect the amount of cash flow available to us to meet our financial commitments and fund capital expenditures. Moreover, because only approximately 47% and 39% of our total expected hydrocarbon production in 2015 and 2016, respectively, is hedged, a significant portion of our estimated production is particularly exposed to commodity price volatility. Oil and natural gas prices also impact our ability to borrow money and raise additional capital. For example, the amount we will be able to borrow under the RBL Revolver is subject to periodic redeterminations based, in part, on current oil and natural gas prices and on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our reserves, which could result in material impairments to our oil and natural gas properties. As a result, if there is a further decline or sustained depression in commodity prices, we may, among other things, be unable to maintain or increase our borrowing capacity, meet our debt obligations or other financial commitments or obtain additional capital, all of which could materially adversely affect our business, results of operations and financial condition.
Our debt agreements restrict our current and future operations and if we default under our debt agreements, our lenders may act to accelerate our indebtedness, which would impact our ability to continue to conduct our business.
Our debt agreements contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our best interest, including restrictions on our ability to:
| incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; |
| pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; |
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| prepay, redeem or repurchase certain debt; |
| make loans, investments and other restricted payments; |
| sell, transfer or otherwise dispose of assets; |
| create or incur liens; |
| enter into transactions with affiliates; |
| alter the businesses we conduct; |
| enter into agreements restricting our subsidiaries ability to pay dividends; and |
| consolidate, merge or sell all or substantially all of our assets. |
In addition, we are subject to a financial performance covenant under the credit agreement governing the RBL Revolver, which, subsequent to the March 18, 2015 amendment, requires us to maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 (up from 1.5 to 1.0 previously) as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015. For the fourth quarter of 2015, we are required to maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 1.5 to 1.0, after which, beginning with the first quarter of 2016, the credit agreement requires us to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 as of the end of each fiscal quarter through maturity. In addition, the March 18, 2015 amendment requires us to maintain minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the Second Lien Term Loan. These covenants could restrict our ability to engage in certain actions, including by potentially limiting our ability to sell assets, make future borrowings under the RBL Revolver, incur other additional indebtedness, or make certain interest payments. Our ability to meet the financial performance covenant and liquidity covenant can be affected by events beyond our control, such as changes in commodity prices, and there can be no assurance that we will be able to comply with these covenants in future periods. In addition, if we receive additional waivers or amendments to our RBL Revolver, our lenders may impose additional operating and financial restrictions on us or modify the terms of the RBL Revolver.
Our long-term debt is reflected as a current liability in our consolidated balance sheet as of December 31, 2014 due to uncertainty regarding our ability to comply with certain restrictive covenants contained in our debt agreements. A breach of the covenants under our debt agreements (including certain reporting and administrative requirements, such as, but not limited to, the form and content of the auditors report, providing financial statements, compliance certificates and other documents to our counterparties to the Debt Agreements under prescribed timelines) could result in an event of default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related indebtedness and may result in the acceleration of any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, an event of default under the credit agreement governing the RBL Revolver would permit the lenders under the RBL Revolver to terminate all commitments to extend further credit under that facility. Furthermore, if we were unable to repay the amounts due and payable under the RBL Revolver and the Second Lien Term Loan, those lenders could proceed against the collateral granted to them to secure that indebtedness. In the event our debt holders accelerate the repayment of our borrowings, we may not have sufficient assets to repay that indebtedness and we could be forced into bankruptcy or liquidation.
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We may be unable to maintain compliance with the Consolidated First Lien Debt to Consolidated EBITDA Ratio in 2015, Consolidated Total Debt to Consolidated EBITDA Ratio in 2016 and $150.00 million of liquidity required of us by provisions contained in the Credit Agreement and subsequent amendments which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.
The credit agreement governing the RBL Revolver requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of December 31, 2014, we are in compliance with our financial covenants. Unless the financial performance and/or our liquidity covenant is amended further or we are successful in implementing a strategic alternative to improve our capital structure, we do not expect to remain in compliance with all of our restrictive covenants in our Credit Agreement. As a result, our long-term debt is reflected as a current liability in our consolidated balance sheet at December 31, 2014. Any failure to comply with the conditions and covenants in our Credit Agreement that is not waived by our lender or otherwise cured could lead to a termination of our Credit Agreement, acceleration of all amounts due under our Credit Agreement, or trigger cross-default provisions under other financing arrangements. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our Credit Agreement impose on us.
Oil and natural gas prices are volatile. If oil and natural gas prices remain weak or deteriorate our borrowing base may be reduced and we may be required to repay a portion of the RBL Revolver which could result in an event of default under the credit agreement governing such facility.
Our ability to access funds under the RBL Revolver is based on a borrowing base, which is subject to periodic redeterminations based on our proved reserves and prices that will be determined by our lenders using the bank pricing prevailing at such time. If the prices for oil and natural gas remain weak or deteriorate, if we have a downward revision in estimates of our proved reserves, or if we sell additional oil and natural gas reserves, our borrowing base may be reduced. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the facility exceeding the borrowing base, we will be required to repay the deficiency within 30 days or in six monthly installments thereafter, at our election. We may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility, which could result in an event of default.
A downgrade in our debt ratings could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit, increase our borrowing costs and potentially require us to post letters of credit for certain obligations.
We may sell or otherwise dispose of certain of our properties as a result of our evaluation of our asset portfolio and to help enhance our liquidity. Such dispositions could materially adversely affect our business, results of operations and financial condition.
Since the Acquisition, we have sold approximately $1.2 billion of assets, and we may pursue additional divestitures or other asset monetization transactions as we continue to evaluate our asset portfolio and to help enhance our liquidity. Dispositions of assets could affect our future performance by reducing our production and
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reserves and, for purposes of calculating compliance with the financial performance covenant under the RBL Revolver, could reduce our consolidated EBITDA on a pro forma historical basis. These transactions also have inherent risks, including possible delays in closing transactions (including potential difficulties in obtaining regulatory approvals), the risk of lower-than-expected sales proceeds for the disposed assets and potential post-closing claims for indemnification. In addition, the current commodity price environment may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing. In addition, we may not realize any expected cost savings from asset dispositions, in part because of revenue losses from the divested properties.
Our substantial indebtedness, liquidity issues and potential to seek protection under the federal bankruptcy laws has impacted, and may continue to impact, our business and operations.
Due to the uncertainty about our future, there is risk that, among other things:
| third parties confidence in our ability to explore and produce oil and natural gas could erode, which could impact our ability to execute on our business strategy; |
| it may become more difficult to retain, attract or replace key employees; |
| employees could be distracted from performance of their duties or more easily attracted to other career opportunities; and |
| our suppliers, hedge counterparties, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us. |
The occurrence of certain of these events has already negatively affected our business and may have a material adverse effect on our business, results of operations and financial condition.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could materially adversely affect our business, results of operations and financial condition.
Our operations are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenue to return a profit. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, as well as production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, the results of our exploratory drilling in new or emerging areas are more uncertain than drilling results in areas that are developed and have established production, and our operations may involve the use of recently-developed drilling and completion techniques. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. Further, many factors may curtail, delay or cancel drilling and completion projects, including the following:
| delays or restrictions imposed by or resulting from compliance with regulatory and contractual requirements; |
| delays in receiving governmental permits, orders or approvals; |
| differing pressure than anticipated or irregularities in geological formations; |
| equipment failures or accidents; |
| adverse weather conditions; |
| surface access restrictions; |
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| loss of title or other title related issues; |
| shortages or delays in the availability of, increases in the cost of, or increased competition for, drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals and supplies; and |
| restrictions in access to or disposal of water resources used in drilling and completion operations. |
Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment and skilled personnel as demand for rigs, equipment and personnel has increased along with the number of wells being drilled. These factors may, among other things, cause significant increases in costs for equipment, services and/or personnel. Such shortages or increases in costs could significantly decrease our profit margin, cash flow and operating results, or restrict our operations in the future.
The occurrence of certain of these events, particularly equipment failures or accidents, could impact third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant property damage. As a result, we face the possibility of liabilities from these events that could materially adversely affect our business, results of operations and financial condition.
Estimates of proved reserves and future net cash flows are not precise. The actual quantities of our proved reserves and our future net cash flows may prove to be lower than estimated.
Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. Our estimates of proved reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate, including, but not limited to, future commodity prices, the quantities of oil and natural gas that are ultimately recovered, future operating and development costs, future taxes (such as severance, ad valorem, excise and other similar taxes) and the effect of governmental regulations. Because all reserve estimates are to some degree subjective, the actual results of certain items may differ materially from those assumed in estimating reserves. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Our actual production, revenue and expenditures with respect to reserves will likely be different from estimates and the differences may be material.
The standardized measure of discounted future net cash flows (the Standardized Measure) included in this report should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. The prices used in calculating the Standardized Measure and in estimating our quantities of proved reserves are, in accordance with SEC requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ended December 31, 2014, average prices used to calculate our Standardized Measure and in estimating our quantities of proved reserves were $94.99 per Bbl for crude oil and $4.35 per MMBtu for natural gas (before differentials). Commodity prices declined significantly in the fourth quarter of 2014 and continued this trend in early 2015. If commodity prices remain at current levels, our future calculations of the Standardized Measure and estimated quantities of proved reserves will be based on these lower commodity prices, which would result in the removal of non-economic reserves from our proved reserves in future periods. Holding all other factors constant, if commodity prices used in our year-end reserve estimates were decreased to forward pricing at February 3, 2015, the discounted net future cash flows of our proved reserves at December 31, 2014 would decrease by approximately 45%.
Actual future net cash flows also will be affected by other factors, including:
| the amount and timing of actual production; |
| levels of future capital spending; |
| increases or decreases in the supply of, or demand for, oil and natural gas; and |
| changes in governmental regulations or taxation. |
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Accordingly, our estimates of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor mandated by the rules and regulations of the SEC to be used in calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Therefore, the estimates of our discounted future net cash flows should not be construed as accurate estimates of the current market value of our proved reserves. Should our actual proved reserves and related net cash flows differ from our estimates, it may materially adversely affect our business, results of operations and financial condition.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate and are dependent upon economically viable commodity prices to justify development. Therefore, our estimated proved undeveloped reserves may not ultimately be developed or produced.
Approximately 16.1% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2014. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of these reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the discounted future cash flows of our estimated proved undeveloped reserves and future net cash flows estimated for such reserves and may result in some projects becoming uneconomic. In addition, pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. Accordingly, delays in the development of such reserves, increases in capital expenditures required to develop such reserves and changes in commodity prices could cause us to have to reclassify our proved undeveloped reserves as unproved reserves, which may materially adversely affect our business, results of operations and financial condition.
Our business requires substantial capital expenditures, and any inability to obtain needed capital or financing on satisfactory terms or at all, or any negative developments in the capital markets, could have a material adverse effect on our business.
The oil and natural gas industry is capital intensive. We have historically financed our capital expenditures through cash flows from operations, borrowings under our RBL Revolver and the sale of assets. Our cash flow from operations and access to capital are subject to a number of variables, including:
| our proved reserves; |
| the level of oil and natural gas we are able to produce from existing wells; |
| the prices at which we are able to sell oil and natural gas; |
| our ability to acquire, locate and produce new reserves; |
| global credit and securities markets; and |
| the ability and willingness of lenders and investors to provide capital and the cost of that capital. |
Because of these factors, we may not be able to adequately finance capital expenditures at a level to grow our business.
Moreover, as a result of our significant indebtedness and the recently volatility in commodity prices, we have significantly reduced our planned capital spending on drilling and completion activities in 2015 as compared to prior years. This reduction in capital expenditures may curtail the development of our properties, which in turn could lead to a decline in our production and reserves and could materially adversely affect our business, results of operations and financial condition.
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Our future drilling activities are scheduled over an extended time period, making them susceptible to uncertainties that could materially alter the occurrence or timing of such drilling.
We have identified certain potential drilling locations as an estimation of our future drilling activities on our existing acreage. Our ability to drill and develop these potential drilling locations depends on a number of uncertainties, including: (i) our ability to timely drill wells on lands subject to complex development terms and circumstances; (ii) the availability and cost of capital, equipment, services and personnel; (iii) seasonal conditions; (iv) regulatory and third-party permits, orders and approvals; (v) oil and natural gas prices; (vi) drilling and completion costs; and (vii) and well results. Because of these uncertainties, we do not know if such potential drilling locations will ever be drilled or if we will be able to produce oil and/or natural gas from these or any other potential drilling locations. Moreover, unless production is established or other operations are conducted on a timely basis with respect to the undeveloped acres on which some of our potential drilling locations are located, the leases for such acreage may expire. If we are not able to renew or otherwise maintain leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. Therefore, our actual drilling activities may materially differ from those presently estimated, which could materially adversely affect our business, results of operations and financial condition.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would materially adversely affect our business, results of operations and financial condition.
Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can also change under other circumstances, many of which are outside of our control. As a result, our future oil and natural gas reserves and production and, therefore, our cash flow and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties 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. Moreover, we have significantly reduced our planned capital spending on drilling and completion activities in 2015 as compared to prior years, which could curtail the development of our properties and result in a decline in our production and reserves for future periods. Further, a significant delay between when we discontinue drilling activities and when we restart our drilling program could negatively impact our ability to restart such activities when conditions warrant in the future. If we are unable to replace our current and future production, the value of our reserves could decrease, and our business, results of operations and financial condition would be materially adversely affected.
Full cost accounting rules may require us to record certain non-cash asset write-downs in the future, which could materially adversely affect our results of operations.
We utilize the full cost method of accounting for oil and natural gas activities. Under full cost accounting, we are required to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or ceiling, of the book value of oil and natural gas properties. To the extent that the book value of our oil and natural gas properties exceed the ceiling, a non-cash impairment charge is recorded. The impairment charge may not be reversed in future periods even if the calculated ceiling increases. The mechanics of the ceiling test are described in Part II, Item 8Financial Statements and Supplementary Data.
As of December 31, 2014 and 2013, we had approximately $2.2 billion and $3.9 billion, respectively, of costs that were excluded from amortization. These costs relate to the amounts associated with unproved properties and wells in progress. Costs associated with unproved properties are assessed at least annually to ascertain whether impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment has occurred. The facts and circumstances included in our impairment assessment are described in Part II, Item 8Financial Statements and
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Supplementary Data. During any period in which impairment is indicated, some or all of the accumulated costs incurred to date for the impaired property become part of our amortization base and are then subject to depletion and the full cost ceiling limitation. Accordingly, a significant change in the factors considered for impairment, many of which are beyond our control, may shift a significant amount of cost from unproved properties into our amortization base and negatively impact the results of our full cost ceiling test. During the years ended December 31, 2014, 2013 and 2012, we recorded approximately $1.7 billion, $1.6 billion and $1.3 billion, respectively, of impairments associated with our unproved property.
During the years ended December 31, 2014, 2013 and 2012, we recorded full cost ceiling test impairments of approximately $2.3 billion, $1.8 billion and $2.3 billion, respectively, as a result of our quarterly ceiling tests. We could incur additional material write-downs in the future, particularly as a result of a decline of oil and natural gas prices, impairments of costs associated with unproved properties or changes in reserve estimates. If product prices remain at current levels, impairment expense in 2015 will be material.
We may incur substantial losses and be subject to substantial claims as a result of our oil and natural gas operations. Additionally we may not be insured for, or our insurance may be inadequate to protect us, against these risks.
Our oil and natural gas operations are subject to all of the risks associated with exploring, drilling for and producing oil and natural gas, including the possibility of:
| environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including soil or groundwater contamination; |
| abnormally pressured formations; |
| mechanical failures and difficulties, such as stuck oilfield drilling and service tools and casing collapse; |
| fires, explosions and ruptures of pipelines; |
| fires and explosions at well locations or involving associated equipment; |
| personal injuries and death; |
| natural disasters; and |
| terrorist attacks targeting oil and natural gas related facilities and infrastructure. |
It is impossible for us to predict the magnitude of any such event and whether our contingency plans would be sufficient to allow us to successfully respond to such an event in a way that would prevent a material interruption in our business operations. Any of these risks could materially adversely affect our ability to conduct operations or result in substantial damages and losses to us as a result of, or claims for, personal injury or loss of life, damage to property or the environment, regulatory investigations or penalties, suspension of our operations or repair and remediation costs.
We do not insure fully against all risks associated with our business either because such insurance is not available or because we believe that the cost of available insurance is excessive relative to the risks presented. In addition, our insurance policies have materiality deductibles, self-insurance levels and limits on our maximum recovery, and the amount of our insurance coverage for a particular risk may be insufficient to compensate us for any losses that we may actually incur. A loss not covered or not fully covered by insurance could materially adversely affect our business, results of operations and financial condition.
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The success of our operations depends, in part, on other parties, particularly with respect to properties we do not operate, which could reduce our production and revenue or could result in increased liabilities for environmental or safety related incidents.
A significant portion of our properties are operated by other parties. With respect to such properties, we have limited ability to influence or control day-to-day operations, including those relating to compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to such properties. As a result, the success and timing of drilling and development activities on such properties depend upon factors outside of our control, including the operators compliance with the applicable operating or similar agreement, the timing and amount of capital expenditures, the operators expertise and financial resources, the inclusion of other participants in drilling wells and the use of technology. Furthermore, we may not be able to remove the operator of our non-operated properties in the event of poor performance. In addition, even with respect to our operated properties, we may depend upon third-party working interest owners to fund their respective share of capital expenditures to successfully execute a project. Such limitations and dependence on other parties could cause us to incur unexpected future costs and materially adversely affect our business, results of operations and financial condition.
We rely on independent experts and technical or operational service providers over whom we may have limited control.
We use a variety of independent contractors to provide us with certain technical assistance and services. For example, we rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services (including completions), to drill and complete wells within our prospects. Our limited control over the activities and business practices of these service providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially adversely affect our business, results of operations and financial condition.
There is significant competition in the oil and natural gas industry, which may materially adversely affect our ability to successfully implement our business strategies.
The oil and natural gas industry is intensely competitive, and we compete with other companies that possess and employ financial, technical and personnel resources that are substantially greater than ours. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Our competitors may be able to pay more for oil and natural gas leases and mineral estates, productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of oil and natural gas leases, properties and prospects than our financial or personnel resources permit. Such competition can also drive up the costs to acquire oil and natural gas leases, properties and prospects in areas where we are already conducting business and operations.
In addition, because of our significant indebtedness and liquidity constraints, many of our competitors have a greater ability than us to continue exploration and development activities during periods of low oil and natural gas prices and/or higher service costs. The more favorable capital structure of these companies may also give them better access to capital and on better terms, which could give such companies an advantage in the financing and execution of acquisitions and their drilling programs. Moreover, our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could materially adversely affect our competitive position.
New technologies may cause our current exploration and drilling methods to become obsolete.
The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to
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implement new technologies at a substantial cost. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We may not be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.
The loss of officers or other key personnel could materially adversely affect our business.
Our ability to hire and retain our officers and other key personnel, including geologists, geophysicists, engineers and other professionals, is important to our performance and operations. Competition for qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. In addition, our substantial indebtedness may make the recruitment and retention of qualified personnel more difficult. If we are unable to retain our current officers and other key employees and/or recruit new officers and employees of comparable knowledge and experience, our business, results of operations and financial condition may be materially adversely affected.
We may not realize any or all of our projected cost savings from our recent cost-reduction efforts, including a reduction in our workforce, and those efforts could materially adversely affect our business.
In March 2015, we began implementing comprehensive cost-reduction efforts to decrease our long-term recurring expenses and to improve operational efficiencies (the Cost Reduction Plan). These efforts included a reduction in our workforce of approximately 30% across multiple functions throughout the Company. The Cost Reduction Plan, including the related reduction in force, and any other cost reduction measures we may take in the future, may not result in the expected cost savings and may distract management from our core business, harm our reputation or yield unanticipated consequences, such as attrition beyond the planned reduction in workforce, difficulties in attracting and hiring new employees, increased difficulties in the execution of our day-to-day operations, reduced employee productivity, inability to complete certain tasks necessary to enhance our future operations such as further development of management reporting systems and a deterioration of employee morale. In addition, we expect to have to rely more on consultants and service providers and incur additional costs to further retain remaining key employees in connection with the Cost Reduction Plan. In addition, as a result of the Cost Reduction Plan, we currently estimate that we will record restructuring charges in excess of $30.0 million, which are expected to be recorded primarily in the first quarter of 2015. Our estimated restructuring charges are based on a number of assumptions, and the actual results may differ materially from our expectations and additional charges not currently expected may be incurred in connection with, or as a result of, these reductions.
We may be unable to make attractive acquisitions or successfully integrate acquired assets or businesses, and any inability to do so may disrupt our business and hinder our ability to grow. In addition, any acquisitions we do complete will be subject to substantial risks.
In the future we may make acquisitions of assets or businesses that complement or expand our current business. If we are unable to make these acquisitions for any reason, including because we are: (i) unable to identify attractive acquisition candidates, to analyze acquisition opportunities successfully from an operational and financial point of view or to negotiate acceptable purchase contracts with them; (ii) unable to obtain financing for these acquisitions on economically acceptable terms; or (iii) outbid by competitors, then our future growth could be limited.
Furthermore, even if we do make acquisitions they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated. Any acquisition involves potential risks that could
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significantly impair our ability to manage our business and materially adversely affect our business, results of operations and financial condition, including, among other things:
| mistaken assumptions about volumes, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt; |
| difficulties in integrating the operations, technologies, products and personnel of the acquired companies; |
| difficulties in complying with regulations, such as environmental regulations, and managing risks related to an acquired business or assets; |
| timely completion of necessary financing and required amendments, if any, to existing agreements; |
| an inability to implement uniform standards, controls, procedures and policies; |
| undiscovered, unknown and unforeseen problems, defects, liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects; |
| assumption of liabilities that were not disclosed to us or that exceed our estimates; |
| diversion of managements and employees attention from normal daily operations of the business; |
| difficulties in entering regions in which we have no or limited direct prior experience and where competitors in such regions have stronger operating positions; and |
| potential loss of key employees. |
Moreover, our reviews of acquired properties are inherently incomplete since it is generally not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it necessarily permit a buyer 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 groundwater contamination, are not necessarily observable even when an inspection is undertaken. The inability to make future acquisitions or adequately evaluate the impact of such acquisitions could materially adversely affect our business, results of operations and financial condition.
Our business operations could be disrupted if our information technology systems fail to perform adequately.
The efficient operation of our business depends on our information technology systems. We rely on our information technology systems to effectively manage our business data, communications and other business processes. For example, we implemented a new enterprise resource planning (ERP) software system in 2014 to assist in the management of data across our company. The failure of our information technology systems, including the ERP software system, to perform as we anticipate could disrupt our business and result in transaction errors, processing inefficiencies and the loss of sales and customers, causing our business, results of operations and financial condition to suffer. In addition, our information technology systems may be vulnerable to damage or interruption from circumstances beyond our control, including fire, natural disasters, power outages, systems failures, security breaches and viruses. Any such damage or interruption could materially adversely affect our business, results of operations and financial condition.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market or operational conditions or the unavailability of satisfactory oil and natural gas transportation and infrastructure arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including
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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, transportation, fractionation systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially adversely affect our business. We may be required to curtail production from or shut in wells for a lack of a market or because of inadequacy or unavailability of pipelines, gathering system capacity, transportation or processing, treating and fractionation facilities or refinery demand. If that were to occur, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products at a reasonable cost to market, which could materially adversely affect our business, results of operations and financial condition.
Our use of derivative financial instruments could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in commodity prices, we currently, and may in the future, enter into derivative financial instruments for a portion of our future oil and natural gas production. Such risk management activities will impact our earnings in various ways, including through the recognition of certain mark-to-market gains and losses on our financial derivative instruments, resulting from changes in the fair value of our financial derivative instruments between periods. In addition, our derivative financial instruments may limit the benefit we would otherwise receive from increases in the prices for oil or natural gas and therefore may reduce revenues in the future. Our derivative financial instruments may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or when there are issues with regard to the legal enforceability of such derivative financial instruments.
Our future risk management activities may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative financial instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness. Any such future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.
Our derivative financial instruments also expose us to the risk of financial loss if a counterparty fails to perform under its respective agreement. Disruptions in the financial markets could lead to sudden decreases in a counterpartys liquidity, which could make them unable to perform under the terms of the arrangement and, as a result, we may not be able to realize the benefit of the related derivative financial instrument. Any default by the counterparty under our derivative financial instruments when they become due could materially adversely affect our business, results of operations and financial condition.
We are subject to federal, state, local and other laws, regulations and administrative actions and rule making that could increase our costs, reduce our revenues, cash flows or liquidity, or otherwise alter the way we do business.
The exploration, development, production and sale of oil and natural gas in the United States is subject to extensive federal, state, tribal, local and other laws, regulations and agency actions, including those pertaining to environmental, health and safety, wildlife conservation, gathering and transportation of oil and natural gas, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large expenditures to comply with applicable governmental rules, regulations, permits or orders. For example, certain regulations require the plugging and abandonment of wells, which may result in significant costs associated with the removal of tangible equipment and other restorative actions at the end of oil and natural gas production operations. Because of the subjectivity in
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the assumptions underlying our estimated compliance costs with respect to these requirements and the relatively long lives of most of our wells, the costs to ultimately comply with plugging and abandonment obligations may vary significantly from our estimates, which could materially adversely affect our business, financial condition and results of operations.
Activities subject to regulation include, but are not limited to:
| the location of wells and the methods of drilling and completing wells; |
| disposal of fluids used and wastes generated in connection with drilling, completion and production operations; |
| access to, and surface use and restoration of, surface locations to be used for wells and/or related facilities; |
| plugging and abandoning of wells; |
| air quality, water quality, wetlands, noise levels and related permits; |
| gathering, transporting and marketing of oil and natural gas; |
| taxation; and |
| access to the water resources used in drilling and completion operations. |
In some cases, our operations are subject to federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to state regulations relating to conservation practices and protection of correlative rights. These regulations may affect the timing of our operations, the ability to execute our operations as originally planned and limit the quantity of oil and natural gas we may produce and sell. We generally need to obtain drilling permits from federal, state, local and other governmental authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Failure to comply with such requirements may result in the suspension or termination of operations and subject us to criminal as well as civil and administrative penalties. Compliance costs can be significant. Moreover, the enactment of additional requirements in the future or a change in the interpretation or the enforcement of existing requirements could substantially increase our costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our business, results of operations and financial condition.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety laws and regulations, as well as administrative actions and rule making, applicable to our business.
Our oil and natural gas exploration and production operations are subject to extensive and increasingly stringent federal, state, local and other laws and regulations, as well as administrative actions and rule making, pertaining to the protection of the environment, including those governing the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees, or otherwise relating to pollution or protection of the environment, human health and safety and natural resources. Wellbore integrity regulations have also been enacted and are being considered by a number of regulatory bodies. We may incur significant costs, delays and liabilities as a result of these requirements. We must take into account the cost of complying with such requirements in planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities, including gathering, transportation, and waste treatment, storage and disposal facilities. The regulatory frameworks govern, and often require permits for, the handling of drilling and production materials, water withdrawal, disposal of drilling, completion and production wastes, operation of air emissions sources, and drilling activities, including those conducted on lands lying within wilderness, wetlands, Federal and Indian lands
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and other protected areas. Numerous governmental authorities, such as EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions requiring remediation or limiting or preventing some or all of our operations. Liabilities, penalties, suspensions, terminations or increased costs resulting from any failure to comply with existing environmental, health or safety requirements, or from the enactment of additional requirements in the future or a change in the interpretation or the enforcement of existing requirements, could materially adversely affect our business, results of operations and financial condition.
There is inherent risk in our operations of incurring significant environmental costs and liabilities due to our generation and handling of petroleum hydrocarbons and wastes, because of our air emissions and wastewater discharges, and as a result of historical industry operations and waste disposal practices. Some of our owned and leased properties have been used for oil and natural gas exploration and production activities for a number of years, often by third parties not under our control. The age and condition of some of our assets increases the likelihood that we will incur higher levels of costs associated with environmental, health and safety matters. We and/or other owners and operators of these facilities may have generated or disposed of wastes that allegedly polluted the soil, surface water or groundwater at our facilities and adjacent properties. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance. We could be subject to claims for personal injury, natural resource and property damage (including site clean-up and restoration costs) related to the environmental, health or safety impact of our oil and natural gas production activities, and we have been named from time to time as, and currently are, a defendant in litigation related to such matters. Under certain laws, in particular CERCLA, we also could be subject to joint and several and/or strict liability for the removal or remediation of contamination regardless of whether such contamination was the result of our activities, and even if the operations were in compliance with all applicable laws at the time the contamination occurred. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage (including remediation costs). We have been and continue to be responsible for remediating contamination, including at some of our current and former facilities. Future costs of newly discovered or new contamination may result in a materially adverse impact on our business or operations.
In addition, EPA issued a final rule on April 17, 2012, setting forth new NSPS and NESHAP standards for the oil and natural gas sector. The new rule will be fully implemented in 2015. We are continuing to evaluate the effect of this rule on our business, but we do not currently expect these requirements to materially adversely affect our business, financial condition or results of operations. Because of the subjectivity in the assumptions underlying our estimated compliance costs with respect to this rule, however, the costs to ultimately comply with the rule may vary significantly from our estimates, which could materially adversely affect our business, financial condition and results of operations.
Moreover, current lease terms, permit conditions and stipulations and other governmental regulatory conditions restrict drilling operations and certain other activities during certain times of the year on a significant portion of our properties in the Greater Green River and Powder River basins due to wildlife activity and/or habitat. In addition, the U.S. Fish and Wildlife Service recently announced its decision to list the lesser prairie chicken as threatened under the U.S. Endangered Species Act. The lesser prairie chickens habitat overlaps certain of our properties in Western Oklahoma and the Texas Panhandle. We elected to participate in a related U.S. Fish and Wildlife endorsed conservation plan for the lessor prairie chicken that could restrict our operations and result in additional costs with respect to the affected areas. Under a 2011 settlement, the U.S. Fish and Wildlife Service is required to make a determination on the listing of more than 250 species as endangered or threatened over the next several years. The presence of other wildlife, wildlife habitats or plants, including species that are or will be protected under the U.S. Endangered Species Act, could result in additional restrictions
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on our ability to access and/or operate these and other properties, including with respect to our other core positions, which could materially adversely affect our business, results of operations and financial condition.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Most of our recent drilling operations have been in tight and unconventional oil and natural gas formations, which are completed using hydraulic fracturing. Hydraulic fracturing involves the high-pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. Recently there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and increase the potential for earthquakes. As a result, several federal and state agencies are considering legislation that would increase the regulatory burden imposed on hydraulic fracturing.
Legislation has been proposed in the U.S. Congress to regulate hydraulic fracturing, including proposals to amend the SDWA to require the permitting of every hydraulic fracturing project and the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing groundwater or causing other damage. Such bills, if enacted, could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
There have been several recent federal initiatives related to hydraulic fracturing. In April 2012, the White House issued an executive order creating a multi-agency task force to coordinate federal oversight of hydraulic fracturing. In February 2014, EPA issued an interpretive memorandum to clarify UIC requirements under the SDWA for use of diesel fuels in hydraulic fracturing, and a technical guidance containing recommendations for EPA permit writers to consider in implementing these UIC requirements. These documents clarified that any owner or operator who injects diesel fuels in hydraulic fracturing for oil or gas extraction must obtain a UIC permit before injection. EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities in 2015. In addition, the federal Bureau of Land Management proposed and is in the process of reconsidering regulations requiring disclosure of chemicals used in the hydraulic fracturing process both before and after any drilling on federal public land.
Other EPA initiatives have focused on studies related to hydraulic fracturings potential impact on drinking water. At the request of the U.S. Congress, EPA is undertaking a national study to understand the potential impacts of hydraulic fracturing on drinking water resources. The study has included a review of published literature, analysis of existing data, scenario evaluation and modeling, laboratory studies, and case studies. EPA issued a progress report in December 2012 detailing the steps being undertaken in the study, and it expects to release a final draft report for peer review and comment in 2015. In December 2011, the EPA published a draft report finding that hydraulic fracturing is a likely cause of drinking water contamination in the vicinity of Pavillion, Wyoming; however, in September 2013, the EPA announced that it does not plan to finalize or seek peer review of the report, and that it will continue to support the State of Wyoming in the States investigation of the groundwater contamination. Findings such as this could increase public pressure on governmental authorities to implement new regulations regarding hydraulic fracturing.
Many states have adopted or are considering regulations regarding hydraulic fracturing, including requiring the disclosure of chemicals injected during hydraulic fracturing. Vermont banned hydraulic fracturing in the state in 2012 and certain states such as New York and New Jersey issued moratoriums on hydraulic fracturing while they considered studies of and regulations regarding hydraulic fracturing, although New York announced in December 2014 that it will move to ban hydraulic fracturing in the state in 2015 and New Jerseys moratorium expired in 2013. In some areas hydraulic fracturing has also been the subject of local ordinances attempting to ban or limit the practice; court challenges to such ordinances have had varied outcomes to date. If new federal or state laws or regulations are adopted that significantly increase the risk of legal challenges to, or restrict the use
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of, hydraulic fracturing, such legal requirements could make it more difficult or costly for us to perform hydraulic fracturing and increase our costs of compliance and doing business.
Based on increased regulation and attention given to the hydraulic fracturing process from federal, state and various local governments and increased public scrutiny, greater opposition and litigation toward oil and natural gas production utilizing hydraulic fracturing techniques is anticipated. Additional legislation or regulation could lead to operational delays, increased operating costs or a decrease in completion of new oil and natural gas wells all of which could adversely affect our business, results of operations and financial condition.
Regulation and agency actions related to climate change and the emission of GHGs could result in increased operating costs and reduced demand for oil and natural gas and the physical effects of climate change could disrupt our operations.
Global climate change continues to attract considerable public, scientific and regulatory attention, and GHG emission regulation is becoming more stringent. EPA has taken a number of steps towards regulating GHG emissions under the Clean Air Act, including its Mandatory Reporting of Greenhouse Gases Rule published in October 2009, and expanded in November 2010 to include onshore oil and natural gas production activities, its endangerment and cause or contribute findings under Section 202(a) of the Clean Air Act published in December 2009, and its so-called Tailoring Rule concerning regulation of large emitters of GHGs under the Clean Air Acts PSD Program and Title V program issued in May 2010, which has been subject to litigation. These and future EPA rulemakings regarding GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.
We are currently required to report annual GHG emissions from some of our operations, and additional federal and state GHG emission related requirements that are in various stages of development may also affect our operations. In response to the U.S. Presidents June 2013 Climate Action Plan, EPA issued a Clean Power Plan designed to cut GHG emissions from existing fossil-fuel fired power plants in June 2014, proposed standards for modified and reconstructed fossil-fuel fired power plants in June 2014, and issued a revised proposal with standards for new fossil fuel-fired plants in September 2013. In March 2014, the Obama administration announced a strategy to reduce methane emissions, which was followed by the administrations January 2015 announcement of a goal to cut methane emissions from the oil and gas sector by 40-45 percent from 2012 levels by 2025. EPA expects to issue a proposed rule in the summer of 2015 and final rule in 2016 to reduce methane emissions. In addition to the EPA initiatives, the U.S. Congress has considered, and in the future may again consider, legislation that would establish a nationwide cap-and-trade system for GHGs. A number of states have also begun taking action on their own or as part of a multi-state program to control and/or reduce GHG emissions. Such laws and regulations could require us to modify existing, or obtain new, permits, implement additional pollution control technology, curtail operations or increase significantly our operating costs.
Regulation of GHG emissions could also result in reduced demand for our products, as oil and natural gas consumers seek to reduce their own GHG emissions. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could materially adversely affect our business, reputation, operating performance and product demand. In addition, to the extent climate change results in more severe weather and significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other climatic effects, our own or our customers operations may be disrupted, which could result in a decrease in our available product or reduce our customers demand for products.
The derivatives reform legislation adopted by the U.S. Congress could have a material adverse impact on our ability to hedge risks associated with our business.
The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd- Frank Act) in 2010. This comprehensive financial reform legislation changes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation
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requires the CFTC, the SEC and other regulators to promulgate regulations implementing the new legislation. Among other things, the Dodd-Frank Act and the regulations promulgated under the Dodd-Frank Act impose requirements relating to reporting and recordkeeping, position limits, margin and capital, and mandatory trading and clearing. While many of the regulations are already in effect, the implementation process is still ongoing, and we cannot yet predict the ultimate effect of the regulations on our business. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through restrictions on the types of collateral we are required to post), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties, all of which could materially adversely affect our business, results of operations and financial condition.
We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax preferences currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.
The U.S. Presidents proposed budget for fiscal 2014 contains a proposal to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate certain tax preferences that are currently available with respect to oil and natural gas exploration and development. Any such change could materially adversely impact our business, results of operations and financial condition by increasing the costs we incur which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of on-going litigation, so the classification or reclassification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or the U.S. Congress, which could cause our revenue to decline and operating expenses to increase, thereby materially adversely affecting our business, results of operations and financial condition.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements and may possibly require the reporting of rates charged for the services provided. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could materially adversely affect our business, results of operations and financial condition.
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If we fail to maintain effective internal controls over financial reporting at a reasonable assurance level, we may not be able to accurately report our financial results, which could have a material adverse effect on investor confidence, our business and the trading prices of our securities.
We have established internal controls over financial reporting. However, internal controls over financial reporting may not prevent or detect misstatements or omissions in our financial statements because of their inherent limitations, including the possibility of human error, the circumvention or overriding of controls or fraud. Therefore, even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, we may be unable to provide financial information in a timely and reliable manner within the time periods required for our financial reporting under SEC rules and regulations and the terms of the agreements governing our indebtedness. Any such difficulties or failure could materially adversely affect our business, results of operations and financial condition.
In connection with the preparation of our financial statements for the years ended December 31, 2013 and 2012, we identified material weaknesses in our internal controls over financial reporting. A material weakness is a deficiency, or combination of deficiencies, in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. With respect to both the 2013 and 2012 annual financial statements, we identified material weaknesses in our internal controls related to the valuation and disclosure of our estimated proved reserves due to ineffective controls associated with the review of certain underlying data and assumptions utilized in the reserve valuation process. We also identified a material weakness related to the preparation of the cash flow statement resulting from misclassifications between operating activities and investing activities of certain transactions which were corrected in our consolidated financial statements. With respect to the 2012 annual financial statements, the identified material weaknesses also included deficiencies related to ineffective controls over manual journal entries, cash flow hedge designations and information technology general controls.
In connection with managements evaluation of disclosure controls and procedures as of December 31, 2014, we identified certain control deficiencies we considered to be significant deficiencies in our internal control over financial reporting. A significant deficiency in internal controls is a deficiency, or combination of deficiencies, in internal control over financial reporting that is less severe than a material weakness, yet important enough to merit attention by those responsible for oversight of our financial statements. The control deficiencies related to information technology general controls, insufficient documentation related to control activities performed in connection with the preparation of our year end reserve report, and controls related to the purchase and receipt of goods and services associated with certain expenditures. No financial statement adjustments were recorded as a result of the control deficiencies.
Due to a transition period established by rules of the Securities and Exchange Commission, we have not evaluated our internal controls over financial reporting, the purpose of which would be for management to report on the effectiveness of our internal controls over financial reporting that would be needed to comply with Section 404(a) of the Sarbanes Oxley Act of 2002. However, we will be required to include a report of managements assessment regarding internal control over financial reporting in our next annual report. As we progress towards complying with the reporting requirements associated with internal controls over financial reporting as prescribed in the Sarbanes Oxley Act of 2002, we may discover other internal control deficiencies in the future and/or fail to adequately correct previously identified control deficiencies, which could materially adversely affect our business, results of operations and financial condition.
Additionally, as a result of our March 2015 workforce reduction, we expect changes to occur in our internal controls over financial reporting. The changes could relate to different employees performing internal control activities than those who have previously performed those activities or revisions to our actual control activities as we evaluate the appropriate internal control structure after our workforce reduction. A changing internal control environment increases the risk that our system of internal controls is not designed effectively or that internal control activities will not occur as designed.
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Actual and potential litigation could have a material adverse effect on our business, results of operations and financial condition in future periods.
We are subject to claims arising from disputes in the normal course of business, including from third-party operators, customers, former and existing employees, vendors and other third parties. These risks may result in lawsuits or other proceedings brought against us or by us. A variety of claims or causes of action have been and may be asserted in lawsuits and proceedings, including, without limitation, contract, tort, common law and equitable claims, and may include multiple plaintiffs or seek certification of a large class of plaintiffs. These risks may be difficult to assess or quantify and their existence and magnitude may remain unknown for substantial periods of time. If the plaintiffs in any suits against us were to successfully prosecute their claims, or if we were to settle such suits by making significant payments to the plaintiffs, our business, results of operations and financial condition would be harmed. Even if the outcome of a claim proves favorable to us, litigation can be time consuming and costly and may divert management resources. If any of our directors or officers were named in any lawsuit, our indemnification obligations could magnify the costs of these suits.
Audits by governmental authorities and third parties could materially adversely affect our business, results of operations and financial condition.
We are subject, from time to time, to audits and investigations by governmental and tribal authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as our compliance with unclaimed property (escheatment) requirements and other laws. Unclaimed property laws generally require us to turn over to certain governmental authorities the property of others held by us that has been unclaimed for a specified period of time. In addition, other parties with an interest in wells operated by us have the ability under various contractual agreements to perform audits of our billing practices where we receive reimbursements from these owners for their share of the costs incurred in connection with the oil and natural gas properties that we operate. An unfavorable resolution of a claim brought pursuant to any of the foregoing could materially adversely affect our business, results of operations and financial condition.
Our operations depend on the availability of water. Limitations or restrictions on our ability to obtain, use or dispose of water may have a material adverse effect on our business, results of operations and financial condition.
Water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water, or to dispose of water after use, could adversely impact our operations. In certain areas, water may not be available from local sources because of droughts or other factors, resulting in increased operating costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition, waste water disposal or water recycling requirements could limit our ability to obtain or dispose of water.
In addition, concerns have been raised about the potential for earthquakes to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities. New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others. We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of water necessary for hydraulic fracturing of wells or the disposal of water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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Affiliates of KKR, ITOCHU and the other investors own substantially all of the equity interests in us and may have conflicts of interest with us or our other stakeholders.
As a result of the Acquisition, KKR, ITOCHU and certain other co-investors, including investment funds affiliated with Crestview Partners II GP, L.P. and Natural Gas Partners IX, L.P., indirectly own substantially all of our capital stock through our Principal Stockholders, and the Principal Stockholders designees hold all of the seats on our board of directors. As a result, affiliates of KKR, ITOCHU and the other investors have control over our decisions to enter into any corporate transaction and have the ability to prevent any transaction that requires the approval of stockholders regardless of whether any of our other stakeholders believe that any such transactions are in their own best interests. For example, affiliates of KKR, ITOCHU and the other investors could collectively cause us to make acquisitions that increase the amount of our indebtedness or to sell assets, or could cause us to issue additional capital stock or declare dividends. So long as these investors continue to indirectly own a significant amount of the outstanding shares of our capital stock or otherwise control a majority of our Board of Directors, affiliates of KKR, ITOCHU and the other investors will continue to be able to strongly influence or effectively control our decisions. Our debt agreements permit us, under certain circumstances, to pay advisory and other fees, pay dividends and make other restricted payments to, or otherwise enter into transactions with, KKR, ITOCHU and the other investors or their respective affiliates, and KKR, ITOCHU and the other investors or their respective affiliates may have an interest in our doing so.
Additionally, KKR, ITOCHU and the other investors are in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us or that supply us with goods and services. KKR, ITOCHU and the other investors may also pursue acquisition opportunities that may be complementary to our business and, as a result, those acquisition opportunities may not be available to us. In addition, KKRs, ITOCHUs and the other investors interests in other portfolio companies could impact our ability to pursue acquisition and divestiture opportunities. You should carefully consider that the interests of KKR, ITOCHU and the other investors may materially conflict with or differ from the interests of our other stakeholders. See Part III, Item 12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and Item 13Certain Relationships and Related Transactions, and Director Independence.
Terrorist or cyber-attacks and threats could have a material adverse effect on our business, results of operations and financial condition.
Terrorist or cyber-attacks may significantly affect the energy industry, including our operations and those of our customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, results of operations and financial condition.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under the RBL Revolver and the Second Lien Term Loan are at variable rates of interest and expose us to interest rate risk. Assuming all revolving loans were fully drawn under the RBL Revolver as of December 31, 2014, each quarter point change in interest rates would result in a $5.0 million change in annual interest expense on indebtedness under the RBL Revolver and the Second Lien Term Loan. We have not maintained interest rate swaps with respect to our variable rate indebtedness, and any swaps we may enter into may not fully mitigate our interest rate risk, may prove disadvantageous or may create additional risks, including the risks discussed above.
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ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
ITEM 2. | PROPERTIES |
The information called for by this item is included in Part I, Item 1Business and is incorporated herein by reference.
ITEM 3. | LEGAL PROCEEDINGS |
From time to time, we are party to various legal proceedings arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of currently pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. For additional information, see the discussion under Litigation and Contingencies in Note 18 to our audited consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
ITEM 4. | MINE SAFETY DISCLOSURES |
Not applicable.
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ITEM 5. | MARKET FOR OUR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
There is no public trading market for shares of our common stock, and we do not have any equity securities that are registered pursuant to Section 12 of the Exchange Act.
During 2014, we awarded a total of 10.0 million shares of restricted stock, as well as 3.7 million stock options, having an exercise price of $2.50 per share. These awards were made to certain officers and other employees of the Company pursuant to the Samson Resources Corporation 2011 Stock Incentive Plan. The awards were not registered under the Securities Act in reliance upon Section 4(a)(2) of the Securities Act, as transactions not involving a public offering, and Rule 12h-1 under the Exchange Act. For additional information regarding equity incentive awards made under the 2011 Plan, see Part III, Item 11Executive Compensation and Note 14 to our audited consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
ITEM 6. | SELECTED FINANCIAL DATA |
The following table provides selected historical consolidated financial data as of and for the periods shown. The historical consolidated financial data for the periods labeled as Successor reflect the accounts of Samson Resources Corporation and its subsidiaries on a consolidated basis. The historical consolidated financial data for the periods labeled as Predecessor reflect the accounts of our Predecessor. The balance sheet data as of December 31, 2014 and 2013 and the consolidated statements of loss and cash flow data for the Successor years ended December 31, 2014, 2013 and 2012 have been derived from our audited consolidated financial statements included in this report. The balance sheet data as of December 31, 2012 and 2011 and the consolidated statements of income (loss) and cash flow data for the Successor period from inception (November 14, 2011) through December 31, 2011 have been derived from our audited consolidated financial statements not included in this report. The balance sheet data as of June 30, 2011 and 2010 and the consolidated statements of income (loss) and cash flow data for the Predecessor period from July 1, 2011 through December 21, 2011 and the Predecessor fiscal years ended June 30, 2011 and 2010 have been derived from our Predecessors audited consolidated financial statements not included in this report. The historical operating results of the Company and our Predecessor are not necessarily indicative of future operating results.
We have experienced many changes in our business during the periods shown in the table below, which significantly limits the comparability of the financial data. These changes and other factors affecting comparability include, but are not limited to:
| the formation of Samson Resources Corporation on November 14, 2011 and the Acquisition, which occurred on December 21, 2011; |
| the reorganization transaction made in connection with the Acquisition, which allowed the selling stockholders to retain the Gulf Coast Assets of our Predecessor; |
| the disposition by our Predecessor of a significant portion of its oil and natural gas properties located in the Permian Basin in January 2011; |
| our divestiture of certain Bakken properties in the Williston Basin in December 2012; |
| our restructuring plan initiated in December 2012, which resulted in the closure of our Midland, Texas office and a reduction in force of 120 employees across the Company; and |
| we operate on a December 31 fiscal year end, while the Predecessor operated on a June 30 fiscal year end. |
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The following selected historical financial data should be read together with the information included under Part II, Item 7Managements Discussion and Analysis of Financial Condition and Results of Operations and the audited consolidated financial statements and the accompanying notes of the Company included in Part II, Item 8Financial Statements and Supplementary Data of this report.
Successor | Predecessor | |||||||||||||||||||||||||||
(dollars in thousands) |
Year Ended December 31, | From Inception (November 14, 2011) through December 31, 2011 |
July 1, 2011 through December 21, 2011 |
Year Ended June 30, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | 2011 | 2010 | ||||||||||||||||||||||||
Statement of income (loss) data: |
||||||||||||||||||||||||||||
Total revenues, net |
$ | 1,177,696 | $ | 1,083,581 | $ | 1,167,940 | $ | 54,901 | $ | 838,720 | $ | 1,302,713 | $ | 1,659,179 | ||||||||||||||
Impairment of oil and gas properties |
2,325,346 | 1,817,670 | 2,253,527 | | | | | |||||||||||||||||||||
Total operating expenses(1) |
3,295,133 | 2,800,863 | 3,459,207 | 169,870 | 962,540 | 966,754 | 1,017,544 | |||||||||||||||||||||
Operating income (loss) |
(2,117,437 | ) | (1,717,282 | ) | (2,291,267 | ) | (114,969 | ) | (123,820 | ) | 335,959 | 641,635 | ||||||||||||||||
Net income (loss) from continuing operations |
(1,420,581 | ) | (1,105,374 | ) | (1,530,029 | ) | (73,667 | ) | (118,963 | ) | 205,688 | 401,207 | ||||||||||||||||
Net income (loss) |
$ | (1,420,581 | ) | $ | (1,105,374 | ) | $ | (1,530,029 | ) | $ | (73,667 | ) | $ | (118,963 | ) | $ | 205,688 | $ | 385,067 | |||||||||
Statement of cash flows data: |
||||||||||||||||||||||||||||
Net cash provided by (used in): |
||||||||||||||||||||||||||||
Operating activities |
$ | 487,557 | $ | 688,627 | $ | 531,864 | $ | (553,520 | ) | $ | 410,554 | $ | 1,426,645 | $ | 1,298,600 | |||||||||||||
Investing activities |
(812,301 | ) | (764,281 | ) | (489,884 | ) | (6,897,175 | ) | (924,786 | ) | (991,092 | ) | (1,055,739 | ) | ||||||||||||||
Financing activities |
347,843 | 73,342 | (165,670 | ) | 7,577,424 | (95,000 | ) | (157,156 | ) | (20,138 | ) | |||||||||||||||||
Balance sheet data (end of period): |
||||||||||||||||||||||||||||
Cash and cash equivalents |
$ | 23,826 | $ | 727 | $ | 3,039 | $ | 126,729 | $ | 631,632 | $ | 353,161 | ||||||||||||||||
Total property, plant and equipment, net |
5,114,384 | 7,040,932 | 8,603,426 | 10,894,512 | 4,964,665 | 4,643,495 | ||||||||||||||||||||||
Total assets |
5,608,312 | 7,437,686 | 9,036,657 | 11,504,279 | 5,945,959 | 5,560,379 | ||||||||||||||||||||||
Total debt (including debt classified as current)(2) |
4,107,808 | 3,745,035 | 3,648,894 | 3,756,503 | 695,000 | 695,000 | ||||||||||||||||||||||
Shareholders equity |
191,525 | 1,512,742 | 2,589,986 | 4,074,213 | 2,776,108 | 2,867,156 | ||||||||||||||||||||||
Other financial data: |
||||||||||||||||||||||||||||
Total capital expenditures |
$ | 968,883 | $ | 1,080,964 | $ | 1,119,255 | $ | 2,561 | $ | 919,648 | $ | 1,587,755 | $ | 1,120,279 |
(1) | The total operating expenses for the Successor period from inception (November 14, 2011) through December 31, 2011 includes $137.4 million in expenses related to the Acquisition or related activities. |
(2) | Includes Cumulative Preferred Stock for the Successor periods presented. |
50
ITEM 7. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
You should read the following discussion and analysis in conjunction with Part II, Item 6Selected Financial Data and our audited consolidated financial statements and accompanying notes included in Part II, Item 8Financial Statements and Supplementary Data of this report. This discussion and analysis contains forward-looking statements regarding industry outlook, our expectations regarding our future performance, liquidity and capital resources and other non-historical statements that are based on managements current expectations, estimates and projections about our business and operations. Our actual results may differ materially from those contained in, or implied by, any forward-looking statements. These forward-looking statements are subject to numerous risks and uncertainties, including, but not limited to, the risks and uncertainties described and referenced in Part I, Item 1ARisk Factors and in the Cautionary Statement Regarding Forward-Looking Statements section of this report.
Overview
We are an independent oil and gas company engaged in the exploration, development and production of oil and gas properties located onshore in the United States. We operate our business and properties through our West Division, which includes properties primarily in the Rocky Mountain region, and our East Division, which includes properties primarily in the Mid-Continent and East Texas regions. At December 31, 2014, we had approximately 1.6 million net acres under lease, contract or other means of ownership and control. Our assets include a number of potential growth opportunities, including a significant amount of undeveloped properties with leases held by current production that we believe contain reserves from which we could realize value in the event of future increases in oil and natural gas prices and adequate liquidity, among other factors.
Recent Developments
In 2014 our strategic focus was evaluating our asset base for the purpose of determining which assets we considered core assets capable of supporting long-term, sustainable drilling programs with acceptable returns. For noncore assets, we pursued divestiture opportunities, or other transactions to monetize the assets. We intended to use the proceeds of any divestitures to support our capital program or increase available funds for use in acquisitions of oil and gas properties that would be complimentary to existing core assets or create a new core asset. During 2014, we received approximately $146.7 million of proceeds from sales of oil and gas properties. In December 2014, we acquired developed and undeveloped oil and gas properties to complement our acreage position in East Texas for approximately $57.6 million.
In the last half of 2014, we began actively marketing larger packages of oil and gas properties for divestiture. In the first quarter of 2015, we closed a transaction to sell properties associated with the Arkoma Basin in Oklahoma for approximately $48.0 million. We have not currently entered into agreements to divest our larger packages, including our Bakken, Wamsutter, San Juan and non-core Mid-Con assets, because we perceived the value offered was less than the value of retaining those properties when economic factors and the impact to our credit position were considered. The offer prices were impacted by the rapid decline in the market price for oil, gas, and NGLs that occurred in the fourth quarter of 2014 with continued weakness in 2015.
The significant decline in oil, gas, and NGL prices will have a material impact to our cash flows, results of operations, and liquidity position. Those declines will limit our ability to comply with restrictive covenants contained in our various credit agreements. Uncertainty regarding our liquidity and our ability to comply with restrictive covenants contained in our various credit agreements, the consequences of the uncertainty, and managements plans to address the uncertainty are described in Note 1 to our audited consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
In March 2015, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant and add a restrictive covenant requiring us to maintain minimum
51
liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the Second Lien Term Loan.
As a result of declining product prices and the significant uncertainty regarding our liquidity, we have adjusted our short term strategic focus. Our 2015 capital budget does not contemplate drilling and completion activities to occur subsequent to the first quarter of 2015. In addition, in March 2015, we began implementing a plan to reduce long-term recurring operating expenses which included a reduction of approximately 30% of our workforce and initiatives to reduce other recurring general and administrative expenses and lease operating expenses. Furthermore, we have engaged advisors to assist with the evaluation of our options to address our liquidity position and strategic alternatives. The strategic alternatives may include, but not be limited to, seeking a restructuring, amendment or refinancing of our outstanding debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the company will be able to successfully restructure its indebtedness, improve our liquidity position, complete any strategic transactions or comply with future debt covenant requirements. For additional information, see Liquidity and Capital Resources section of this report.
Operating Expense Reductions
We have begun implementing a plan to lower long term, recurring operating expenses. In March 2015, we announced the reduction of approximately 30% of our workforce. We are also pursuing reductions in recurring general and administrative expenses that were not compensation related and are evaluating ways to reduce production costs in an environment where we expect declining service costs in response to changing industry conditions.
While we believe our actions will better align our cost structure with our companys financial condition in the long term, we do expect certain increases in short term, non-recurring operating expenses associated with our cost reduction plan and the strategic initiatives described above. For example, we expect significant increases in consulting costs related to strategic advisors and increases in certain costs associated with our workforce reduction, including but not limited to: severance benefits paid pursuant to our officer retention agreements and employee severance plan (described in Notes 15 and 18 to the accompanying consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report) and accelerated expense recognition of cash and stock based incentive awards. We estimate that the severance benefits to be paid in connection with the March 2015 workforce reduction (excluding any accelerated expense recognition associated with previous incentive awards) will exceed $30.0 million.
2015 Capital Budget
Our 2015 capital budget is approximately $156.5 million (excluding capitalized interest and internal costs). In addition to our 2015 capital budget, we expect to pay additional capital for amounts incurred in late 2014. Approximately 60% of our 2015 capital budget, or $93.2 million, is allocated primarily to drilling and completion activities for wells where drilling began in 2014 or early 2015. We anticipate a majority of our 2015 capital budget will be incurred during the first quarter of 2015. A significant portion of our 2015 capital budget is associated with mechanical integrity, safety and environmental compliance programs. As a result, we expect production declines will not be offset with production growth from our 2015 capital program. Production will continue to decline until it is offset with production increases attributable to a new capital program. See the Liquidity and Capital Resources section of this report for further discussion. Consistent with our historical practice, we periodically review our capital expenditures and adjust our capital program based on liquidity, commodity prices and expected performance. Consequently, actual capital expenditures may be more or less than amounts budgeted for 2015.
52
Basis of Presentation
The following discussion and analysis addresses significant changes in our results of operations and capital resources for the year ended December 31, 2014 as compared to the year ended December 31, 2013, and for the year ended December 31, 2013 as compared to the year ended December 31, 2012. This section should be read in conjunction with our audited consolidated financial statements and notes included in Part II, Item 8Financial Statements and Supplementary Data of this report.
Industry Trends and Uncertainties
In addition to company specific factors, our performance is generally impacted by several factors present in the oil and gas industry, including:
| the volatility of oil, natural gas and NGL prices; |
| transportation capacity constraints and interruptions; |
| the level of consumer demand and overall economic activity; |
| the use of alternative fuels; |
| weather conditions and the impact of weather-related events; |
| government regulations and taxes; and |
| world geopolitical and economic events. |
For more detailed information regarding these risks, please see Part I, Item 1A Risk Factors.
Source of Our Revenues
We derive substantially all of our revenues from the sale of oil, natural gas and NGLs that are produced through our interests in oil and properties. As described in Note 8 to our audited consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report, we may use derivative instruments to achieve more predictable cash flows and to reduce our exposure to downward price fluctuations for oil and natural gas.
Market Conditions
Prices for our products are inherently volatile and changes in product prices can significantly impact our revenue, net loss and cash flows. The following table sets forth the average market prices for natural gas and oil for the years ended December 31, 2014, 2013 and 2012 and for the two months ended February 28, 2015:
Two Months Ended February 28, 2015 |
Year Ended December 31, | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Average prices: |
||||||||||||||||
Natural gas (MMBtu)(a) |
$ | 3.03 | $ | 4.42 | $ | 3.65 | $ | 2.79 | ||||||||
Oil (Bbl)(b) |
$ | 49.03 | $ | 93.00 | $ | 97.97 | $ | 94.20 | ||||||||
NGL (Bbl) (c) |
$ | 19.58 | $ | 35.84 | $ | 36.66 | $ | 39.22 |
Average market prices for natural gas and oil decreased significantly in the last part of 2014 with continued weakness into the first quarter of 2015. If product prices remain at levels experienced during the fourth quarter of 2014 and the first quarter of 2015 throughout 2015, we expect significantly lower revenues and operating cash flows compared to historical results. In addition, lower product prices would also result in material full cost ceiling test impairment expense in future periods.
(a) | Based on NYMEX last day settlements. |
(b) | Based on NYMEX calendar month average settlements. |
(c) | Based on Samsons NGL component blend utilizing OPIS daily mid-point pricing for Conway and Mont Belvieu. |
53
Results of Operations
2014 Compared to 2013 and 2013 Compared to 2012
Oil, Natural Gas and NGL Revenue
Our oil, natural gas and NGL revenues are derived from the sale of oil, natural gas and NGLs and do not include the effects of the settlements of our derivative positions. Oil, natural gas and NGL revenues are impacted by the volume of product sold and our realized price. The following table sets forth information regarding our oil, natural gas, and NGL revenues for the years ended December 31, 2014, 2013 and 2012 (in thousands):
Crude Oil | Natural Gas | NGLs | Total | |||||||||||||
Revenue for the year ended December 31, 2012 |
$ | 517,824 | $ | 387,731 | $ | 140,947 | $ | 1,046,502 | ||||||||
Change due to volumes |
(77,242 | ) | (89,915 | ) | 21,667 | (145,490 | ) | |||||||||
Change due to price |
53,302 | 197,794 | (10,116 | ) | 240,980 | |||||||||||
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Revenue for the year ended December 31, 2013 |
$ | 493,884 | $ | 495,610 | $ | 152,498 | $ | 1,141,992 | ||||||||
Change due to volumes |
(27,981 | ) | (60,801 | ) | (266 | ) | (89,048 | ) | ||||||||
Change due to price |
(38,522 | ) | 88,928 | (6,973 | ) | 43,433 | ||||||||||
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Revenue for the year ended December 31, 2014 |
$ | 427,381 | $ | 523,737 | $ | 145,259 | $ | 1,096,377 | ||||||||
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Pricing
The following table sets forth information regarding average realized sales prices for the years ended December 31, 2014, 2013 and 2012:
Year Ended December 31, | ||||||||||||||||||||
2014 | Change | 2013 | Change | 2012 | ||||||||||||||||
Average realized sales prices: |
||||||||||||||||||||
Crude oil, unhedged ($/Bbl) |
$ | 85.63 | (7.3 | )% | $ | 92.38 | 10.1 | % | $ | 83.92 | ||||||||||
Natural gas, unhedged ($/Mcf) |
$ | 3.87 | 18.0 | % | $ | 3.28 | 51.2 | % | $ | 2.17 | ||||||||||
NGLs, unhedged ($/Bbl) |
$ | 31.11 | (3.7 | )% | $ | 32.30 | (7.8 | )% | $ | 35.03 | ||||||||||
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Average realized price, unhedged ($/Mcfe) |
$ | 5.68 | 5.2 | % | $ | 5.40 | 23.6 | % | $ | 4.37 | ||||||||||
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Crude oil, hedged ($/Bbl)(a) |
$ | 82.35 | (4.6 | )% | $ | 86.30 | 5.3 | % | $ | 81.93 | ||||||||||
Natural gas, hedged ($/Mcf)(a) |
$ | 3.65 | 8.3 | % | $ | 3.37 | 12.0 | % | $ | 3.01 | ||||||||||
NGLs, hedged ($/Bbl)(a) |
$ | 31.03 | (5.0 | )% | $ | 32.67 | (8.9 | )% | $ | 35.85 | ||||||||||
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Average realized price, hedged ($/Mcfe) |
$ | 5.43 | 2.1 | % | $ | 5.32 | 7.5 | % | $ | 4.95 | ||||||||||
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(a) | The effects of hedges include cash settlements for both derivatives designated as cash flow hedges and those not designated as cash flow hedges. |
Natural Gas Prices
Natural gas prices are subject to variances based on local supply and demand conditions as well as rapidly evolving market conditions. A significant majority of our natural gas sales contracts are based upon index pricing that varies widely as a result of many factors, such as geography. Most of our natural gas is sold on a monthly basis using a monthly index price or a daily basis using daily market prices for a given period. Our average realized natural gas price increased for the years ended December 31, 2014 and 2013 primarily as a result of higher market pricing.
54
We primarily utilize fixed price swaps and collars, and occasionally basis swaps, to manage our exposure to fluctuations in natural gas prices. For the years ended December 31, 2014 and 2013, approximately 82% and 83%, respectively, of our natural gas production was economically hedged with financial derivatives.
Crude Oil Prices
The majority of our crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. These factors include supply fluctuations, changes in demand, pipeline and refinery outages, weather patterns and global events and economics. Most of our crude oil is sold on a monthly basis based upon a variable differential to NYMEX that fluctuates as a result of regional fundamentals. Our realized crude oil price decreased for the year ended December 31, 2014 and increased for the year ended December 31, 2013 primarily as a result of these market forces.
We utilize fixed price swaps to manage our exposure to crude oil prices. For the years ended December 31, 2014 and 2013, the notional amount of our crude oil hedges exceeded our actual production. For periods subsequent to December 31, 2014, we do not expect the notional amount of our crude oil hedges to exceed our actual production.
NGL Prices
Our NGLs are sold based upon published monthly average market pricing less a deduction for transportation and fractionation. Recently, there has been significant volatility in NGL pricing. That volatility has a significant impact on our realized price for NGLs. Additionally, the market price of our NGL production, which primarily consists of ethane, propane, butane, iso-butane and natural gasoline, can be impacted by local market conditions, such as fractionation availability and business conditions of the end users of such NGL products, such as chemical companies, plastic manufacturers and propane dealers. Our average realized NGL price decreased for the years ended December 31, 2014 and 2013 as a result of decrease in overall market NGL pricing.
We utilize fixed price swaps to manage our exposure to NGL pricing. For the years ended December 31, 2014 and 2013, approximately 58% and 50% of our NGL production was economically hedged with financial derivatives.
Commodity Derivatives
We utilize commodity-based derivative instruments to manage our exposure to changes in expected future cash flows from forecasted sales of oil, natural gas and NGLs. All of our derivative activity is designed to reduce our exposure to declining prices. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, and to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses. Changes in the fair value of derivative instruments not designated as accounting hedges are recognized in commodity derivatives, net in our consolidated statements of loss and comprehensive loss in the periods in which they occur. Accordingly, our future earnings may be volatile.
We have designated a portion of our derivatives as cash flow hedges for accounting purposes. The effective portion of changes in fair values of our derivatives designated as cash flow hedges are recorded through other comprehensive income (loss) and do not impact net income (loss) until the underlying physical transaction settles. Once the underlying physical transaction settles, the cash settlement gain or loss on the related cash flow hedge is recorded as commodity derivatives, net in our consolidated statements of loss and comprehensive loss. Any change in the fair value of cash flow hedges resulting from ineffectiveness is recognized in current earnings in commodity derivatives, net.
55
The following table sets forth the components of the composition of our commodity derivatives, net in our consolidated statements of loss and comprehensive loss (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Derivative settlements: |
||||||||||||
Natural gas derivatives |
$ | (29,952 | ) | $ | 13,799 | $ | 138,092 | |||||
Oil derivatives |
(16,389 | ) | (32,490 | ) | (14,312 | ) | ||||||
NGL derivatives |
(378 | ) | 1,747 | 3,362 | ||||||||
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Total settlements |
(46,719 | ) | (16,944 | ) | 127,142 | |||||||
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Total gains (losses) on derivatives: |
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Natural gas derivatives |
48,633 | (16,996 | ) | (77,582 | ) | |||||||
Oil derivatives |
53,752 | (13,449 | ) | 64,737 | ||||||||
NGL derivatives |
10,734 | (11,022 | ) | 5,493 | ||||||||
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Total gains (losses) on derivatives |
113,119 | (41,467 | ) | (7,352 | ) | |||||||
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Ineffectiveness recorded on cash flow hedges |
14,919 | | 1,648 | |||||||||
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Total commodity derivatives, net |
$ | 81,319 | $ | (58,411 | ) | $ | 121,438 | |||||
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Production
The following table sets forth information regarding our average net daily production for the years ended December 31, 2014, 2013 and 2012.
Year Ended December 31, | Pro Forma(a) Excluding Bakken Divestitures |
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2014 | Change | 2013 | Change | 2012 | 2012 | Change | ||||||||||||||||||||||
Production volumes: |
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Natural gas (MMcf/d): |
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West Division |
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Williston |
1.9 | 1.4 | 0.5 | (2.6 | ) | 3.1 | | 0.5 | ||||||||||||||||||||
Powder River |
2.2 | (0.1 | ) | 2.3 | (0.6 | ) | 2.9 | |||||||||||||||||||||
Greater Green River |
30.8 | (15.8 | ) | 46.6 | 3.2 | 43.4 | ||||||||||||||||||||||
San Juan |
80.0 | (12.5 | ) | 92.5 | (17.4 | ) | 109.9 | |||||||||||||||||||||
East Division |
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Mid-Continent West |
46.7 | (4.5 | ) | 51.2 | (11.2 | ) | 62.4 | |||||||||||||||||||||
Mid-Continent East |
70.7 | 0.8 | 69.9 | (5.8 | ) | 75.7 | ||||||||||||||||||||||
East Texas |
136.8 | (11.6 | ) | 148.4 | (40.3 | ) | 188.7 | |||||||||||||||||||||
Other(b) |
1.3 | (0.7 | ) | 2.0 | (0.3 | ) | 2.3 | |||||||||||||||||||||
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Total |
370.4 | (43.0 | ) | 413.4 | (75.0 | ) | 488.4 | 485.5 | (72.1 | ) | ||||||||||||||||||
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Crude oil (Bbl/d): |
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West Division |
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Williston |
3,674.7 | (376.4 | ) | 4,051.1 | (3,873.1 | ) | 7,924.2 | 3,236.8 | 814.3 | |||||||||||||||||||
Powder River |
3,878.4 | 685.7 | 3,192.7 | (28.0 | ) | 3,220.7 | ||||||||||||||||||||||
Greater Green River |
771.7 | (196.2 | ) | 967.9 | 353.8 | 614.1 | ||||||||||||||||||||||
San Juan |
0.5 | 0.2 | 0.3 | (0.2 | ) | 0.5 | ||||||||||||||||||||||
East Division |
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Mid-Continent West |
1,784.2 | (1,317.4 | ) | 3,101.6 | 667.2 | 2,434.4 | ||||||||||||||||||||||
Mid-Continent East |
2,269.3 | 313.8 | 1,955.5 | 565.9 | 1,389.6 | |||||||||||||||||||||||
East Texas |
1,254.1 | 90.1 | 1,164.0 | 91.0 | 1,073.0 | |||||||||||||||||||||||
Other(b) |
40.6 | (95.0 | ) | 135.6 | (55.1 | ) | 190.7 | |||||||||||||||||||||
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Total |
13,673.5 | (895.2 | ) | 14,568.7 | (2,278.5 | ) | 16,847.2 | 12,159.7 | 2,409.0 | |||||||||||||||||||
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Year Ended December 31, | Pro Forma(a) Excluding Bakken Divestitures |
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2014 | Change | 2013 | Change | 2012 | 2012 | Change | ||||||||||||||||||||||
NGL (Bbl/d): |
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West Division |
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Williston |
214.5 | 151.6 | 62.9 | (290.5 | ) | 353.4 | 23.5 | 39.4 | ||||||||||||||||||||
Powder River |
189.4 | (11.5 | ) | 200.9 | 66.1 | 134.8 | ||||||||||||||||||||||
Greater Green River |
2,873.4 | (665.0 | ) | 3,538.4 | 1,455.1 | 2,083.3 | ||||||||||||||||||||||
San Juan |
14.6 | (19.6 | ) | 34.2 | 11.6 | 22.6 | ||||||||||||||||||||||
East Division |
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Mid-Continent West |
3,789.5 | (142.1 | ) | 3,931.6 | (280.4 | ) | 4,212.0 | |||||||||||||||||||||
Mid-Continent East |
2,872.0 | 613.9 | 2,258.1 | 283.3 | 1,974.8 | |||||||||||||||||||||||
East Texas |
2,810.8 | 34.3 | 2,776.5 | 576.6 | 2,199.9 | |||||||||||||||||||||||
Other(b) |
28.1 | 15.0 | 13.1 | (0.9 | ) | 14.0 | ||||||||||||||||||||||
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Total |
12,792.3 | (23.4 | ) | 12,815.7 | 1,820.9 | 10,994.8 | 10,664.8 | 2,150.9 | ||||||||||||||||||||
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Combined Production (Mmcfe/d): |
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West Division |
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Williston |
25 | | 25 | (28 | ) | 53 | 19.7 | 5.3 | ||||||||||||||||||||
Powder River |
27 | 4 | 23 | | 23 | |||||||||||||||||||||||
Greater Green River |
53 | (21 | ) | 74 | 14 | 60 | ||||||||||||||||||||||
San Juan |
80 | (13 | ) | 93 | (17 | ) | 110 | |||||||||||||||||||||
East Division |
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Mid-Continent West |
80 | (13 | ) | 93 | (9 | ) | 102 | |||||||||||||||||||||
Mid-Continent East |
102 | 7 | 95 | (1 | ) | 96 | ||||||||||||||||||||||
East Texas |
161 | (11 | ) | 172 | (36 | ) | 208 | |||||||||||||||||||||
Other(b) |
2 | (1 | ) | 3 | (1 | ) | 4 | |||||||||||||||||||||
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Total |
530 | (48 | ) | 578 | (78 | ) | 656 | 622.4 | (44.4 | ) | ||||||||||||||||||
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(a) | The production from the Williston business unit for the year ended December 31, 2012 includes production attributable to the Bakken properties divested in the fourth quarter of 2012. The pro forma information presented represents 2012 production excluding these properties. |
(b) | Other reflects our interests in certain non-core assets located throughout the continental United States. |
Natural Gas Production
Year ended December 31, 2014Average daily natural gas production decreased 10.4% as compared to 2013. Contributing to lower daily production volumes were divestitures primarily in our Greater Green River business unit as well as non-core assets in our East Texas business unit. Additionally, production volumes were negatively impacted by declines in base production of dry gas assets, primarily in the East Texas and San Juan business units, which were partially offset by horizontal drilling activity.
Year ended December 31, 2013Average daily natural gas production decreased 15.4% as compared to 2012. The decrease in natural gas production volumes in 2013 compared to 2012 was attributable to natural gas declines in base production of dry gas assets due to our focus on developing liquids-rich areas during 2013.
Crude Oil Production
Year ended December 31, 2014Average daily crude oil production decreased 6.1% as compared to 2013. Reduced drilling activity during the year resulted in lower daily production volumes as declines in base production more than offset production from new wells. Declining base production accounts for decreases in our Mid-Continent West, Williston and Greater Green River business units. Also contributing to the decrease in production were divestitures of various properties, primarily in our Williston and East Texas business units. These decreases
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were partially offset by new production during the year resulting from our drilling program, focusing on the Shannon and Sussex formations in the Powder River business unit, the Bakken and Three Forks formations in our Williston business unit, and the Marmaton and Mississippi formations in the Mid-Continent East business unit.
Year ended December 31, 2013Average daily crude oil production decreased 13.5% as compared to 2012 as a result of the divestiture of certain Williston properties in the fourth quarter of 2012. The production decrease from the divestiture was offset by increases in oil production from new wells completed in late 2012 and in 2013 in our Mid-Continent East, Mid-Continent West and Greater Green River business units.
NGL Production
Year ended December 31, 2014Average daily NGL production decreased less than 1.0% as compared to 2013. The decrease was attributable to declines in base production from wells in our Greater Green River, East Texas, and Mid-Continent West business units but was offset by new production due to drilling activity in our Williston, East Texas and Mid-Continent East business units.
Year ended December 31, 2013Average daily NGL production increased 16.6% as compared to 2012. The increase was attributable to our focus during 2013 on developing liquids-rich areas that contain wet natural gas, which allowed for higher recoveries of NGLs. NGL production increased in the Mid-Continent East, East Texas and Greater Green River business units as a result of new wells completed in late 2012 and in 2013.
Operating Expenses
The following tables set forth information regarding operating expenses for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per unit data):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating expenses: |
||||||||||||
Lease operating |
$ | 210,161 | $ | 195,918 | $ | 222,597 | ||||||
Production and ad valorem taxes |
78,453 | 76,256 | 82,651 | |||||||||
Depreciation, depletion and amortization |
478,740 | 554,010 | 677,978 | |||||||||
Impairment of oil and gas properties |
2,325,346 | 1,817,670 | 2,253,527 | |||||||||
Asset retirement obligation accretion |
4,752 | 4,704 | 4,643 | |||||||||
Restructuring charges |
| | 46,643 | |||||||||
Related party management fee |
22,050 | 21,000 | 20,000 | |||||||||
General and administrative |
175,631 | 131,305 | 151,168 | |||||||||
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Total operating expenses |
$ | 3,295,133 | $ | 2,800,863 | $ | 3,459,207 | ||||||
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Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Average cost per unit of combined production ($ per Mcfe): |
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Production costs: |
||||||||||||
Lease operating expense(1) |
$ | 1.09 | $ | 0.93 | $ | 0.93 | ||||||
Production and ad valorem taxes |
0.41 | 0.36 | 0.34 | |||||||||
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Total production cost per unit |
$ | 1.50 | $ | 1.29 | $ | 1.27 | ||||||
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Depreciation, depletion and amortization |
$ | 2.48 | $ | 2.65 | $ | 2.84 | ||||||
General and administrative expenses(2) |
$ | 0.91 | $ | 0.62 | $ | 0.63 |
(1) | Includes stock based compensation expense of $0.03 and $0.02 for the years ended December 31, 2014 and 2013, respectively. |
(2) | Includes stock based compensation expense of $0.27, $0.12 and $0.15 for the years ended December 31, 2014, 2013 and 2012, respectively. |
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Lease operating expenses (LOE). LOE increased $14.2 million in 2014 as compared to 2013. On a per unit basis, LOE per Mcfe increased $0.16 in 2014 as compared to 2013. The increase in LOE from 2013 primarily related to increased relative production in business units with higher production costs as well as increases in maintenance and workover expenses as a result of our production optimization efforts.
LOE decreased $26.7 million in 2013 as compared to 2012. On a per unit basis, there was no change in LOE per Mcfe in 2013 as compared to 2012. The decrease in LOE from 2012 was attributable to a decrease in total production of 29.1 Bcfe, which decreased lease operating expenses as we shifted our drilling focus to areas containing a higher mix of oil and natural gas liquids. The divestitures of the Bakken properties in the fourth quarter of 2012 impacted our oil production and contributed $14.3 million of the total decrease in lease operating expenses for 2013.
Production and ad valorem taxes. Production and ad valorem taxes increased $2.2 million in 2014 as compared to 2013. The increase in expense for the twelve months ended December 31, 2014 resulted from a reduction of ad valorem tax expense recorded in the first quarter of 2013 to reflect actual property tax assessments that were less than previous estimates as well as severance tax incentives received throughout the year of 2013. On a per unit basis, production and ad valorem taxes increased by $0.05 per Mcfe in 2014, as compared to 2013 primarily as a result of higher realized pricing and ad valorem tax adjustments to reflect property tax assessments.
Production and ad valorem taxes decreased $6.4 million in 2013 as compared to 2012. The decrease in expense in 2013 resulted from a reduction of ad valorem tax expense recorded in the first quarter of 2013 to reflect actual property tax assessments that were less than previous estimates. On a per unit basis, production and ad valorem taxes increased by $0.02 per Mcfe in 2013, as compared to 2012 as a result of higher realized pricing for natural gas and crude oil. Higher average realized pricing for natural gas and crude oil was offset by decreases in production of these products as compared to 2012, resulting in lower total production and ad valorem tax expense.
Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense decreased $75.3 million in 2014 as compared to 2013 and decreased $124.0 million in 2013 as compared to 2012 primarily due to ceiling test impairments recorded during 2013 and 2012 of approximately $1.8 billion and $2.3 billion, respectively. A ceiling test impairment lowers the overall depletion base for subsequent periods. The decrease in 2014 and 2013 also resulted from lower overall production as compared to the prior year end. On a per unit basis, depreciation, depletion and amortization expense decreased by $0.17 in 2014, as compared to 2013, and decreased by $0.19 in 2013, as compared to 2012, as a result of lower total proved reserve volumes as compared to the prior year end.
Impairment of oil and gas properties. We recorded pre-tax impairment expense related to our oil and gas properties for the years ended December 31, 2014, 2013 and 2012 of $2.3 billion, $1.8 billion and $2.3 billion, respectively, as a result of our full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of costs associated with our oil and gas properties that can be capitalized in our consolidated balance sheets. Contributing to the impairment expense for the years ended December 31, 2014, 2013 and 2012 were impairments of our unproved properties of approximately $1.7 billion, $1.6 billion and $1.3 billion, respectively, as well as changes to the value of our proved reserves used in our ceiling test calculation. For further information regarding full cost ceiling tests, refer to Note 1 to our consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report and our discussions under Critical Accounting Policies, Practices and Estimates.
Related party management fee. We have an agreement with affiliates of our initial equity investors pursuant to which we receive management services and incur a quarterly management fee to our private equity sponsors. In accordance with the agreement, the management fee increases 5% on an annual basis. The related party management fee increased $1.1 million and $1.0 million during the years ended December 31, 2014 and 2013, respectively.
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Restructuring charges. Restructuring charges primarily relate to severance costs paid in December 2012 associated with a workforce reduction pursuant to employee change of control agreements. No restructuring charges were incurred during the years ended December 31, 2014 or 2013.
General and administrative expenses. The following table illustrates the changes in certain categories of general and administrative expenses for the periods presented (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Cash incentive compensation |
$ | 7,524 | $ | | $ | | ||||||
Officer retention awards |
6,431 | | | |||||||||
Other stock based compensation |
44,875 | 24,799 | 35,606 | |||||||||
Other general and administrative expenses |
116,801 | 106,506 | 115,562 | |||||||||
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Total general and administrative expenses |
$ | 175,631 | $ | 131,305 | $ | 151,168 | ||||||
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During the year ended December 31, 2014, cash incentive compensation increased due to the granting of awards beginning in April 2014 and an acceleration of vesting of certain awards that occurred on September 1, 2014. The officer retention awards were approved in the third quarter of 2014. The increase in other stock based compensation during 2014 primarily relates to the modification of outstanding stock options and the issuance of new restricted stock that occurred in the first quarter of 2014, which increased stock compensation expense by $16.1 million for 2014 as compared to 2013. Other general and administrative expenses increased $10.3 million in 2014 as compared to 2013. Contributing to the increase in 2014 was an increase in expense of approximately $2.2 million related to employer contributions for 401(k) matching in the first quarter of 2014, higher compensation expenses of approximately $1.0 million associated with the repurchase of puttable common stock in the first quarter of 2014 and a decrease in certain cost recoveries associated with operated properties of approximately $5.9 million. For additional information, see Note 14 to the accompanying consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
General and administrative expenses decreased in 2013 compared to 2012 due in part to a decrease in stock compensation expenses of $11.1 million. The decrease in stock compensation expense resulted primarily from accelerated vesting that occurred in 2012 in connection with the reduction in workforce described in Note 15 to the accompanying consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report. Contributing to the decrease in other general and administrative expenses in 2013 were reduced expenses associated with certain licencing fees of approximately $4.5 million and reduced transaction costs. The decreases in other general and administrative expenses were also due to a decrease in cash compensation expense of approximately $5.7 million. The decrease in cash compensation expense related to an increase of $8.2 million of severance costs recorded as general and administrative expenses in 2013 whereas severance related costs for 2012 were recorded as restructuring charges, which was offset by decreases in wages and bonuses of approximately $13.9 million resulting from the reduction in workforce that occurred in December 2012.
Interest expense. Interest expense increased $91.9 million in 2014 as compared to 2013. Our interest expense is the difference between our total interest cost and the amount of interest we capitalize during a period. The amount of interest capitalized is based on the amount of unproved property balances that relate to ongoing development activities. Total interest cost before capitalization was $335.0 million, $341.7 million and $279.7 million for the years ended December 31, 2014, 2013 and 2012, respectively. We capitalized interest costs to unproved oil and gas properties of $243.1 million, $341.7 million and $279.7 million during the years ended December 31, 2014, 2013 and 2012, respectively. The increase in total interest cost for the years ended December 31, 2014 and 2013 was the result of additional interest on the Senior Notes, which we began to incur in May 2013 pursuant to the terms of the registration rights agreement relating to the Senior Notes. The decrease in the amount of interest capitalized in 2014 results from lower unproved property balances associated with ongoing development activities.
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Income tax provision. Income tax benefit was $789.5 million, $614.0 million and $805.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. The decrease in the income tax benefit for the years ended December 31, 2014 and 2013 is due to the difference in pre-tax loss between the periods. The effective income tax rate for the years ended December 31, 2014 and 2013 was approximately 36% and approximately 35% for the year ended December 31, 2012. Realization of our deferred tax assets is dependent upon generating sufficient future taxable income and considers the reversing effects of our deferred tax liabilities. Although realization is not assured, we believe it is more likely than not that the deferred tax assets will be realized.
Liquidity and Capital Resources
The following table summarizes factors affecting our liquidity at (in thousands):
February 28, 2015 |
December 31, 2014 |
December 31, 2013 |
December 31, 2012 |
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Cash and cash equivalents |
$ | 220,704 | $ | 23,826 | $ | 727 | $ | 3,039 | ||||||||
Net working capital, including debt classified as current |
$ | (4,114,052 | ) | $ | (4,030,296 | ) | $ | (314,974 | ) | $ | (364,331 | ) | ||||
Net working capital, excluding debt classified as current |
$ | 128,948 | $ | (125,296 | ) | $ | (314,974 | ) | $ | (364,331 | ) | |||||
Total long-term debt |
$ | | $ | | $ | 3,554,000 | $ | 3,475,000 | ||||||||
Cumulative preferred stock subject to mandatory redemption |
$ | 205,513 | $ | 202,808 | $ | 191,035 | $ | 173,894 | ||||||||
Available borrowing capacity under RBL Revolver |
$ | 4,979 | $ | 343,384 | $ | 1,473,819 | $ | 1,553,904 |
As of March 18, 2015, borrowings under our RBL Revolver were $947.0 million, excluding outstanding letters of credit, and we had no available borrowing capacity.
Short-term liquidity
We have historically funded our operations with operating cash flow, borrowings under our various credit facilities, and asset sales. Our most significant cash outlays relate to our capital program, current period operating expenses, payments under various incentive plans, severance related costs, and our debt service obligations described in Notes 10, 14, 15 and 18 in the accompanying consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
The market price for oil, natural gas, and NGLs decreased significantly during the fourth quarter of 2014 with continued weakness into the first quarter of 2015. The decrease in the market price for our production directly reduces our revenues and operating cash flow. We use derivative financial instruments to reduce our exposure to fluctuations in the prices of oil, natural gas and NGLs. The following table summarizes our hedging position associated with 2015 and 2016 production as of December 31, 2014:
Percent of estimated 2015 production hedged |
Weighted average hedged price for existing hedges |
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2015 | 2016 | 2015 | 2016 | |||||||||||||
Oil |
30 | % | | $ | 90.91/Bbl | | ||||||||||
Natural gas |
59 | % | 61 | % | $ | 4.05/MMBtu | $ | 4.04/MMBtu | ||||||||
NGLs |
8 | % | | $ | 37.07/Bbl | |
Our 2015 hedging program will reduce the potential effects of lower cash flows from operations due to decreases in product prices on the portion of production hedged for 2015.
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In addition, the decrease in the market price for our production indirectly impacts our other sources of potential liquidity described above. Lower market prices for our production may result in lower borrowing capacity under our revolving credit facility or higher borrowing costs from other potential sources of debt financing as our borrowing capacity and borrowing costs are generally related to the value of our estimated proved reserves. The weakness in product pricing may also impact our ability to negotiate asset sales at acceptable prices.
We also have substantial debt service obligations over the next several months. In addition to monthly interest payments associated with borrowings outstanding on our RBL Revolver, we are required to pay approximately $110.0 million in interest on our Senior Notes on each of February 15 and August 15 and approximately $12.5 million in interest on our Second Lien Term Loan at the end of each fiscal quarter.
In addition, declining industry conditions and company performance reduces the likelihood that we comply with certain restrictive covenants contained in our credit facilities, which potentially can have severe consequences to our liquidity. Violation of certain restrictive covenants can result in costly waivers or amendments to agreements governing our credit facilities or an acceleration of repayment obligations for outstanding borrowings. In March 2015, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant to provide that we maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015. The consolidated first lien debt to consolidated EBITDA ratio reverts back to 1.5 to 1.0 at the end of the fourth quarter of 2015. Beginning with the first quarter of 2016, the credit agreement requires us to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 as of the end of each fiscal quarter through maturity. Prior to the March 2015 amendment, the financial performance covenant required us to maintain a ratio of first lien debt to consolidated EBITDA of not more than 1.50 to 1.0 for all of 2015 and a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 beginning with the first quarter 2016. In addition, the March 2015 amendment added a restrictive covenant requiring us to maintain, subsequent to July 1, 2015, minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due in 2020 and the second lien term loan credit facility entered into by our subsidiary, Samson Investment Company and waived the restriction on the inclusion of an explanatory paragraph regarding our ability to continue as a going concern in our auditors report for 2014. In addition, the March 2015 amendment lowered the borrowing base of our RBL Revolver to $950.0 million and we used $46.0 million of cash on hand to repay amounts outstanding on the RBL Revolver on the amendment date. The March 2015 amendment also increased the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of the Companys and its restricted subsidiaries proved reserves.
Unless the financial performance covenant and/or the liquidity covenant are amended further, or we are successful in implementing one of the strategic alternatives discussed below, we do not expect to remain in compliance with all of our restrictive covenants contained in agreements governing our credit facilities for all of 2015 or 2016. Consequently, an acceleration of repayments of outstanding borrowings may occur. As a result of the uncertainty regarding our compliance with our restricted covenants, our long-term debt with maturities summarized in Note 10 to our consolidated financial statements are reflected as a current liability in our consolidated balance sheet at December 31, 2014. If an acceleration of repayments of outstanding borrowings were to occur, we may not have access to funding sources sufficient to repay our outstanding obligations. Conditions that are considered an event of default that may result in an acceleration of maturities under our various credit agreements are listed in Part I, Item 1ARisk Factors contained elsewhere in this report.
We have begun implementing plans designed to improve our liquidity. We have reduced our 2015 capital budget, developed plans to reduce long-term recurring operating expenses, and are continuing our efforts to sell certain non-core assets. However, the terms of the RBL Revolver, our Second Lien Term Loan and the indenture governing our Senior Notes require that some or all of the proceeds from certain asset sales be used to
62
permanently reduce outstanding debt which could substantially reduce the amount of proceeds we retain. The covenants in the RBL Revolver, our Second Lien Term Loan and indenture governing our Senior Notes impose limitations on the amount and type of additional indebtedness we can incur, which may significantly reduce our ability to obtain liquidity through the incurrence of additional indebtedness. Additionally, our ability to refinance any of our existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and our financial condition. As a result, we expect declining sales volumes as natural production declines will not be offset with production growth from our 2015 capital program.
Even if we are successful at reducing our costs and increasing our liquidity through asset sales, we do not expect to have sufficient liquidity to satisfy our debt service obligations, meet other financial obligations, and comply with restrictive covenants contained in our various credit facilities. We have engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure. We have received multiple preliminary proposals to provide additional secured financing, as well as an exchange offer and combined financing proposal from certain of our existing bondholders. We do not currently believe that any of these preliminary proposals provide a long term solution to our capital structure challenges or otherwise adequately address our leverage and liquidity constraints, but we intend to continue to explore additional strategic and refinancing alternatives through a private restructuring. However, a filing under Chapter 11 of the U.S. Bankruptcy Code may provide the most expeditious manner in which to effect a capital structure solution. There can be no assurance that we will be able to restructure our capital structure on terms acceptable to us or our financial creditors, or at all.
Cash and Cash Equivalents
All cash is denominated in U.S. dollars and, at times, is invested in highly liquid, investment-grade securities with maturities of three months or less at the time of purchase.
Net Working Capital
Net working capital is the difference between our current assets and our current liabilities. At February 28, 2015, our net working capital, including debt classified as current, was $(4.1) billion. Our most significant current assets include cash on hand of $220.7 million, accounts receivable of $171.5 million, and net derivative assets of $119.9 million. Our accounts receivable balance includes outstanding joint interest billings to other working interest owners in wells we operate and an accrual for our share of revenue associated with product sales that occurred prior to February 28, 2015. The value of our derivative assets are based on the forward market prices for oil, natural gas, and NGLs at February 28, 2015. Actual cash settlements will be more or less than the value of our derivative assets at period end based on changes in the market value of oil, natural gas, and NGLs through the settlement date of the derivative financial instruments.
At February 28, 2015, our net working capital includes an amount of current liabilities of $4.2 billion associated with our long-term debt with maturities summarized in Note 10 to our consolidated financial statements. Our long-term debt is classified as current at February 28, 2015 due to uncertainty regarding our compliance with certain restrictive covenants contained in our credit facilities. Our other significant current liabilities include accounts payable of $90.2 million and accrued liabilities of $200.1 million. Accounts payable represents the amount of invoices we have processed for payment as of a particular date. Accrued liabilities represent an accrual for expenses or capital expenditures incurred as of a particular date which is not reflected in accounts payable. Our most significant items included in accrued liabilities relate to accrued operating expenses, accrued capital expenditures, accrued long term incentive payments and other employee retention programs, and accrued interest associated with outstanding borrowings under our RBL Revolver, Second Lien Term Loans, and Senior Notes.
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Debt
At December 31, 2014, total outstanding debt was approximately $3.9 billion, which excludes approximately $202.8 million of our Cumulative Preferred Stock. Our total debt consists of three separate financing arrangements: the RBL Revolver, which at December 31, 2014, had a total borrowing capacity of approximately $1.0 billion and outstanding borrowings of $655.0 million; our Senior Notes, which were issued in 2012 for an aggregate principal amount of $2.25 billion; and our Second Lien Term Loan, under which we have borrowed an aggregate principal amount of $1.0 billion. The maturities, interest costs, expected interest payments, and restrictive covenants associated with all of our debt is summarized in Note 10 to our consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
In March 2015, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant to provide that we maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015, at which point the first lien debt to consolidated EBITDA ratio reverts back to 1.5 to 1.0 at the end of the fourth quarter of 2015 and beginning with the first quarter of 2016, we are required to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 as of the end of each fiscal quarter through maturity. Prior to the March 2015 amendment, the financial performance covenant required us to maintain a ratio of first lien debt to consolidated EBITDA of not more than 1.50 to 1.0 for all of 2015 and a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 beginning with the first quarter 2016. In addition, the March 2015 amendment added a restrictive covenant requiring us to maintain minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the second lien term loan credit facility entered into by our subsidiary, Samson Investment Company and waived the inclusion of an explanatory paragraph regarding our ability to continue as a going concern in our auditors report for 2014. In addition, the March 2015 amendment lowered the borrowing base of our RBL Revolver to $950.0 million and we used $46.0 million of cash on hand to repay amounts outstanding on the RBL Revolver on the amendment date. The March 2015 amendment also increased the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of our restricted subsidiaries proved reserves.
As described above, the financial performance covenant in the credit agreement governing the RBL Revolver requires us to operate within established financial ratios. In addition, the March 2015 amendment to the credit agreement governing the RBL Revolver requires us to maintain a certain liquidity on the date of certain interest payments made subsequent to July 1, 2015. Our ability to comply with these covenants depends upon our performance and indebtedness, each of which is impacted by numerous factors, including some that are outside of our control. Accordingly, forecasting our compliance with the financial performance and liquidity covenants in future periods is inherently uncertain. Factors that could impact our future compliance with the financial performance and liquidity covenant include future realized prices for the sales of oil, natural gas and natural gas liquids, future production, returns generated by our capital program, future interest costs, future operating costs, future asset sales, and future acquisitions, among others. For example, asset sales could impact our near-term future performance by reducing our production and reserves and, for purposes of calculating compliance with the financial performance covenant, could reduce our consolidated EBITDA on a pro forma historical basis. Moreover, many of these factors could also decrease our total proved reserves and thereby may result in a reduction to our borrowing base under the RBL Revolver, which could adversely impact our liquidity and ability to meet future obligations.
Unless the financial performance covenant and/or the liquidity covenants are amended further, we do not expect to remain in compliance with all of our restrictive covenants contained in the credit agreement governing the RBL Revolver for all of 2015 or into 2016. Collectively, the negative impacts to our liquidity resulting from declining industry conditions and increased uncertainty regarding our ability to comply with restrictive covenants
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in our credit facilities raises substantial doubt about our ability to continue as a going concern as of December 31, 2014 as described in Note 1 to our consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we, our affiliates and/or our equity investors and their respective affiliates, may from time to time seek to repurchase our outstanding debt, including the Senior Notes and Second Lien Term Loan debt, in open market transactions or privately negotiated transactions, by tender offer or otherwise. The amounts involved in any such transactions, individually or in the aggregate, may be material. Further, any such repurchases may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness.
Cumulative Preferred Stock Subject to Mandatory Redemption
Our preferred stock is recorded at its redemption value. The preferred stock is redeemable at our option at any time and is mandatorily redeemable on the earliest to occur of July 1, 2022, or the consummation of an initial public equity offering or a change of control.
Contractual Obligations
Our contractual obligations include long-term debt, interest expense on debt, drilling commitments, derivatives, the Cumulative Preferred Stock, officer retention agreements, cash incentive awards and other operating lease obligations, marketing commitments and non-cancelable equipment purchases. The table below summarizes the maturity dates of our contractual obligations at December 31, 2014 (in thousands):
Payments Due by Period | ||||||||||||||||||||
Total | Less than 1 Year |
1-3 Years | 3-5 Years | More than 5 Years |
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Long-term debt(a) |
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Principal |
$ | 3,905,000 | $ | | $ | 655,000 | $ | 1,000,000 | $ | 2,250,000 | ||||||||||
Interest |
1,338,695 | 283,597 | 551,704 | 475,972 | 27,422 | |||||||||||||||
Drilling commitments(b) |
12,473 | 12,473 | | | | |||||||||||||||
Derivatives |
5,790 | 5,790 | | | | |||||||||||||||
Cumulative preferred stock subject to mandatory redemption |
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Principal(c) |
202,808 | | | | 202,808 | |||||||||||||||
Interest(c) |
182,528 | 16,225 | 44,618 | 48,674 | 73,011 | |||||||||||||||
Officer retention agreements |
28,153 | 28,153 | | | | |||||||||||||||
Cash incentive awards |
12,933 | 12,933 | | | | |||||||||||||||
Other operating leases |
58,674 | 7,032 | 13,662 | 12,839 | 25,141 | |||||||||||||||
Related party management fee(d) |
188,509 | 23,153 | 49,836 | 54,944 | 60,576 | |||||||||||||||
Marketing commitments(e) |
86,830 | 7,074 | 19,846 | 24,076 | 35,834 | |||||||||||||||
Equipment purchases(f) |
7,566 | 7,566 | | | | |||||||||||||||
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Total |
$ | 6,029,959 | $ | 403,996 | $ | 1,334,666 | $ | 1,616,505 | $ | 2,674,792 | ||||||||||
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(a) | Principal payments are based on contractual maturities of our long-term debt. As described in Note 1 to our consolidated financial statements, our long-term debt is classified as a current liability in our consolidated balance sheet at December 31, 2014 due to uncertainty regarding our compliance with certain restrictive covenants contained in our credit facilities. Cash interest expense on our RBL Revolver is estimated assuming (i) a principal balance outstanding equal to the balance at December 31, 2014 of $655.0 million with no principal repayment until the instrument due date of December 21, 2016 and (ii) a fixed interest rate of 2.17%, |
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which was our interest rate at December 31, 2014. Cash interest expense on our Second Lien Term Loan is estimated assuming a fixed interest rate of 5.0%, which was our interest rate at December 31, 2014. |
(b) | Subsequent to December 31, 2014, we terminated approximately $12.5 million of remaining drilling rig commitments and incurred rig termination fees of approximately $5.2 million as a result. |
(c) | The Cumulative Preferred Stock is recorded at its redemption value. As of December 31, 2014 the redemption value is approximately $202.8 million. The Cumulative Preferred Stock is redeemable at our option at any time and is mandatorily redeemable on the earliest to occur of July 1, 2022, or the consummation of an initial public equity offering or a change of control. The contractual obligation for the Cumulative Preferred Stock as of December 31, 2014 is calculated using an estimated redemption date of July 1, 2022 and assumes future payments of interest are made in cash. Additionally, the Cumulative Preferred Stock accrues dividends quarterly at a specified per annum dividend rate. Dividends can be in cash or in-kind at the Companys election. Dividends not paid in cash are cumulative and accrue and compound quarterly. If dividends are paid in kind, consistent with historical practice, then the timing of cash outlays will be delayed to coincide with the redemption date of the Cumulative Preferred Stock. |
(d) | The agreement providing for the related party management fee, which has a ten year term, will also terminate (i) automatically immediately following the consummation of an initial public offering (unless we elect to continue the agreement) and (ii) at our election, in connection with certain sales of shares of our common stock held by our principal stockholders. If the agreement is terminated under such circumstances, then we must pay a termination fee based on the net present value of future payment obligations under the agreement. In March 2015, the shareholders consented to the extension of time for the payment of the quarterly management fee until the earlier of (i) September 30, 2015 and (ii) such time as the shareholders determine to reinstate such payment as described in Part III, Item 13Certain Relationships and Related Transactions, and Director Independence. The payment schedule above reflects the fees incurred each period. The March 2015 extension does not change the amount of management fee incurred pursuant to the consulting agreement. |
(e) | Includes firm transportation and throughput commitments with midstream service companies and pipeline carriers for future gathering and transportation of natural gas to move our production to market. These and other commitments related to gathering and transportation agreements are not recorded in the accompanying consolidated balance sheets. Excluded from the contractual obligations table above are liabilities associated with asset retirement obligations, which totaled $75.7 million as of December 31, 2014. The ultimate settlement and timing cannot be precisely determined in advance. |
(f) | For the next twelve months, we have non-cancelable commitments to purchase approximately $7.6 million of new tubular and related equipment, including inspection and transportation costs, for drilling and completion projects. |
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity and capital resource positions or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments and letters of credit as described in Note 18 to the consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
Capital Expenditures
Total capital expenditures, including acquisitions, capitalized direct internal costs and interest paid, were approximately $968.9 million for the year ended December 31, 2014. Substantially all of our expenditures, excluding interest paid, relate to the acquisition and development of our oil and gas properties with the remaining expenditures relating primarily to the acquisition and construction of facilities used to support our operational requirements. Our capital expenditures include interest and direct internal costs that are capitalized and increase the basis of our oil and gas properties.
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Due to the significant decline in commodity prices and our evaluation of our short term liquidity, we decided to discontinue drilling and completion activity after the first quarter of 2015, which will significantly lower our 2015 capital budget from recent spending levels. The following table summarizes our capital budget for the year ended December 31, 2015, excluding capitalized interest paid (in thousands):
2015 Capital Budget |
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Drilling and completion: |
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West Division |
$ | 52,500 | ||
East Division |
40,700 | |||
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Total drilling and completion |
93,200 | |||
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Leasehold, geological and geophysical |
11,500 | |||
Related field facilities, corporate and other |
51,800 | |||
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Total capital budget, excluding capitalized direct internal costs and interest paid(1) |
$ | 156,500 | ||
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(1) | Amount does not include capital that was incurred in 2014 but expected to be paid in 2015 of approximately $100.0 million to $110.0 million. |
The following table sets forth information regarding capital expenditures for the year ended December 31, 2014 (in thousands):
Drilling and completion |
$ | 558,076 | ||
Tubular oil and gas equipment, prepaid drilling costs and other |
36,005 | |||
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Total drilling and completion |
594,081 | |||
Leasehold, geological and geophysical |
13,460 | |||
Related field facilities, corporate and other |
27,500 | |||
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Total |
635,041 | |||
Capitalized interest paid |
245,366 | |||
Capitalized direct internal costs |
30,845 | |||
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Total capital expenditures excluding acquisitions |
911,252 | |||
Acquisitions |
57,631 | |||
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Total capital expenditures |
$ | 968,883 | ||
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We primarily fund our capital expenditures with our cash flows generated by operations, borrowings under our RBL Revolver or Second Lien Term Loans, and proceeds from asset sales. The actual amount and timing of our expenditures may differ materially from our estimates as a result of actual drilling results, the timing of expenditures by third parties on projects that we do not operate the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions, among other factors. In addition, under certain circumstances we will consider adjusting or reallocating our capital spending plans.
Property acquisitions in 2014 shown above include the cash paid for the Goodrich Acquisition described in Note 2 to the accompanying consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
Divestitures of Oil and Gas Properties
We have historically utilized proceeds from sales of oil and gas properties to supplement other sources of cash to cover our expenditures. For the years ended December 31, 2014, 2013 and 2012, we received total
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proceeds of approximately $156.6 million, $316.7 million, and $735.0 million from sales of oil and gas properties and other property and equipment. Our recent divestiture activity is summarized below:
2015 Divestitures
In the first quarter of 2015, we received approximately $48.0 million from sales of oil and gas properties in the Arkoma basin.
2014 Divestitures
For the year ended December 31, 2014, we had divestitures of oil and gas properties in various regions and received total additional proceeds of approximately $146.7 million.
2013 Divestitures
In June 2013, we completed the sale of certain oil and gas properties in the Permian Basin for approximately $68.0 million.
In September 2013, we completed the sale of certain oil and gas properties in the Trail Unit of Wyomings Vermillion Basin for approximately $106.7 million.
For the year ended December 31, 2013, we had additional divestitures of oil and gas properties in various regions and received total additional proceeds of approximately $136.9 million.
2012 Divestitures
In December 2012, we closed a transaction in which we sold certain Bakken producing and undeveloped properties in North Dakota, for approximately $650.0 million plus certain customary post-closing adjustments. Also in December 2012, we closed a transaction with a separate counterparty to sell certain Bakken producing and undeveloped properties for $30.0 million plus certain customary post-closing adjustments.
Sources and Uses of Cash
The following table summarizes our net change in cash and cash equivalents for the periods shown (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating activities |
$ | 487,557 | $ | 688,627 | $ | 531,864 | ||||||
Investing activities |
(812,301 | ) | (764,281 | ) | (489,884 | ) | ||||||
Financing activities |
347,843 | 73,342 | (165,670 | ) | ||||||||
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Net change in cash |
$ | 23,099 | $ | (2,312 | ) | $ | (123,690 | ) | ||||
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Cash flows from operating activities. Cash flows from operating activities decreased $201.1 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The decrease in cash flows from operating activities was primarily the result of a decrease in oil, natural gas and NGL sales of $45.6 million, increased cash expenses for lease operating and general and administrative costs of $13.1 million and $17.8 million, respectively, as well as an increase in cash payments for settled derivatives of $51.6 million, all as compared to the year ended December 31, 2013. Cash flows from operating activities were also impacted by a decrease in oil and gas revenues held for distribution of $24.4 million, as compared to the year ended December 31, 2013. Additionally, a reduction in our capitalized cash interest expense decreased operating cash flows by $58.4 million during the year ended December 31, 2014.
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Cash flows from operating activities increased $156.8 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The increase in cash flows from operating activities was primarily the result of an increase of $95.5 million related to oil, natural gas and NGL sales and a decrease in lease operating expenses of $26.7 million. Additionally, 2013 benefitted from the absence of approximately $41.0 million in restructuring costs that were paid in 2012.
Cash flows used in investing activities. Cash flows used in investing activities increased $48.0 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The increase in cash flows used in investing activities was primarily the result of a decrease in proceeds from divestitures of oil and gas properties of $160.1 million and an increase in acquisitions of oil and gas properties of $57.6 million partially offset by a decrease in capital expenditures for oil and gas properties and other property and equipment of $169.7 million, all as compared to the year ended December 31, 2013.
Cash flows used in investing activities increased $274.4 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The increase in cash flows used in investing activities was primarily the result of a decrease in proceeds from divestitures of $423.4 million. During 2012, total divestitures of oil and gas properties were approximately $735.0 million as compared to total divestitures during 2013 of $311.6 million. The 2012 divestitures included large Bakken divestitures in the fourth quarter totaling $680.0 million. Capital expenditures, including cash paid for the purchase of the Predecessor business, decreased $147.7 million from 2012 as a result of our focus on drilling and completion capital and constrained spending on leasehold, geological and geophysical projects as well as a decrease in cash paid for the Acquisition of $109.5 million.
Cash flows from financing activities. Cash flows from financing activities increased $274.5 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The increase in cash flows provided by financing activities was primarily the result of an increase in net borrowings under the RBL Revolver of $272.0 million as compared to the year ended December 31, 2013. Borrowings under the RBL Revolver are primarily utilized to fund our capital expenditures as well as for general corporate purposes.
During the year ended December 31, 2013 and the year ended December 31, 2012 we completed the following significant activities:
| During 2013, our payments on our RBL Revolver were $1.2 billion lower than during 2012. We used substantially all of the proceeds from the Second Lien Term Loan and the large divestitures that occurred in the fourth quarter of 2012 to pay down outstanding borrowings on our RBL Revolver. |
| During the year ended December 31, 2012, we issued $2.25 billion in aggregate principal amount of Senior Notes and utilized those proceeds to repay the Bridge Facility. We incurred approximately $51.9 million of debt issuance costs during the year ended December 31, 2012 associated with the Senior Notes offering and the issuance of the Second Lien Term Loan. |
Critical Accounting Policies, Practices and Estimates
Accounting policies that we consider significant are summarized in Note 1 to the accompanying consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report. Certain accounting policies require management to make critical accounting estimates. Accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions involves a high degree of subjectivity and judgment concerning uncertain matters or such matters are subject to future changes and (b) the impact of the estimates and assumptions on our financial position or results of operations is material. Additional information regarding how our critical accounting estimates are determined and the subjectivity of those estimates is provided below.
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Oil and Gas Properties
Accounting for oil and gas properties using the full cost method of accounting requires management to make estimates which have a material impact on the Companys financial position and results of operations as they determine the carrying amount of our proved and unproved oil and gas properties, the amount of depletion expense recorded, and the amount of impairment expense recorded pursuant to the full cost ceiling limitation (if any). We believe the following to be critical accounting estimates associated with our application of the full cost method of accounting for our oil and gas properties:
| Proved reservesProved oil and natural gas reserves are defined by the SEC as the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs based on the unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials and under period-end economic and operating conditions. The process of estimating quantities of proved reserves is complex, requiring subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including additional development activity and evolving production history. Changes in oil, natural gas and NGL prices, operating costs and expected performance from a given reservoir also will result in future revisions to the amount of our estimated proved reserves. Reserve estimates are updated at least annually. Changes to our proved reserves are summarized in Note 23 to our accompanying consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report. Future additions of proved reserves are also directly impacted by the size and success of our capital program. |
All reserve information in this report is based on estimates prepared by our petroleum engineering staff or obtained from a third party reserve engineering firm engaged to report on our companys proved reserves. The subjective nature of reserve estimation increases the likelihood of significant changes in these estimates in future periods as new information becomes available. Any significant changes could have a material impact on future depletion expense and full cost ceiling impairment expense. Assuming a 5% change of estimated proved reserves results in a corresponding change in estimated future net revenues associated with proved reserves (discounted at 10%), such change would impact our full cost ceiling impairment expense for the year ended December 31, 2014 by approximately $128.4 million.
| Future development costs of proved undeveloped reservesAn input to our periodic depletion calculation and our full cost ceiling limitation is our estimate of future development costs associated with proved undeveloped reserves. Costs associated with our drilling and completion activities can change quickly as market conditions change. A 10% change in our estimated future development costs would impact our annual depletion expense by approximately $6.0 million and our full cost ceiling limitation at December 31, 2014 by approximately $22.1 million. |
| Allocations of costs to the depletion baseCosts associated with unproved properties are excluded from our depletion base until proved reserves are established for undeveloped locations or wells are drilled. At that time, costs are moved from unproved properties to proved properties in our consolidated balance sheet and become subject to periodic depletion. The amount of costs transferred is determined based on our estimate of the total number of wells expected to be drilled for a particular geographically defined area. If our estimate of the total number of wells expected to be drilled decreases, then the amount allocated to proved properties for each future well drilled increases. Our estimates of drilling locations are derived from internal reserve reports identifying proved, probable, and possible drilling locations. Significant changes to our estimated drilling locations can have a material impact on future depletion expense or our full cost ceiling impairment expense. For the year ended December 31, 2014, a 10% change in our unproved property allocations associated with these estimated drilling locations would impact our depletion base by $18.0 million with a corresponding change to our full cost ceiling limitation. |
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In addition, costs associated with unproved properties are also transferred to our depletion base, which also reduces our full cost ceiling limitation, when those properties are considered impaired. The effect of impairments to our unproved property is higher future depletion expense and potentially higher full cost ceiling impairment expense. Our decision to impair unproved properties is based primarily on evaluating factors that result in a higher degree of uncertainty regarding our future development plans for our unproved property. Future development plans can be impacted by general market conditions, our financial condition, planned asset sales, or new information gathered concerning the economic viability of developing a particular unproved property.
At December 31, 2014, we have approximately $2.1 billion of unproved property costs excluded from our depletion base. A significant portion of our unproved property relates to value assigned to unproved property in connection with the acquisition of our company in December 2011 and the capitalization of interest cost subsequent to the acquisition. Approximately 64% of our unproved property balance relates to our largest two geographically defined potential development areas, whereas our largest 10 geographically defined potential development areas comprise 89% of our unproved property balance. Our assessment of our unproved properties is a continuous process. Within the last three years we have recorded material impairments as we refine our capital deployment plans and establish the strategic direction for our company. Total impairments of unproved property balances for the years ended December 31, 2014, 2013, and 2012 were $1.7 billion, $1.6 billion, and $1.3 billion, respectively. Changes to our assessment of the uncertainty regarding future development plans, particularly with respect to areas having the largest unproved property balances, would have material impact to our reported earnings through higher depletion expense or full cost ceiling impairment expense.
| Pricing used to calculate the full cost ceiling limitationAlthough the pricing used to estimate the future net revenues from proved properties (discounted at 10%) is prescribed by rules governing the full cost method of accounting for oil and gas properties, changes in prices can materially impact the determination of impairment expense (if any) for a particular period. For example, a 10% decline in prices of oil, natural gas and natural gas liquids used in determining the full cost ceiling limitation would have increased pre-tax impairment expense by approximately $460.2 million for the year ended December 31, 2014. Currently, forward prices are significantly lower than the pricing used to calculate the full cost ceiling limitation at December 31, 2014. If prices remain at current levels, we expect continuing material full cost ceiling test impairment expense in 2015. The following table summarizes the pricing used to determine the full cost ceiling limitation for the periods presented: |
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Oil (per barrel)(a) |
$ | 94.99 | $ | 96.91 | $ | 94.71 | ||||||
Natural gas (per MMBtu)(a) |
$ | 4.35 | $ | 3.67 | $ | 2.76 | ||||||
NGLs (per barrel) |
$ | 33.46 | $ | 34.47 | $ | 38.15 |
(a) | Before adjustment for market differentials. |
Capitalized Interest
Our interest expense is the difference between our total interest cost and the amount of interest we capitalize during a period. The amount of interest capitalized is based on the amount of unproved property balances that relate to ongoing development activities. Our total interest cost incurred in 2014 was $335.0 million, of which $296.9 million was cash interest expense associated with our outstanding debt. Of the total interest cost incurred, $243.1 million was capitalized and $91.9 million was recorded as interest expense. The material impairments recorded for our unproved property balances in recent years decreases the amount of interest cost capitalized for future periods. In addition, our 2015 capital budget does not contemplate any drilling or completion activity after the first quarter. We expect reduced unproved property balances and limited development activity will result in material reductions in the amount of interest cost capitalized, which in turn will result in material increases to our interest expense in 2015 compared to historical periods.
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Capitalized Internal Costs
We capitalize internal costs directly related to exploration or development activities associated with our oil and gas properties. During the years ended December 31, 2014, 2013, and 2012, we capitalized internal costs of approximately $30.8 million, $37.6 million, and $35.8 million, respectively. The amount we capitalize is based on our estimate of employee time spent on exploration or development activity for a particular period. Our 2015 capital budget does not contemplate drilling and completion activities beyond the first quarter of 2015. Consequently, we expect the amount of internal costs capitalized to decrease significantly in 2015.
Asset Retirement Obligations
We have obligations to remove tangible equipment and restore land at the end of oil and natural gas production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells. We develop estimates of these costs for each of our significant areas of operation based upon their geographic type, type of production structure, reservoir depth and characteristics, and currently available information. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future asset retirement obligations on an annual basis, or more frequently, if an event occurs or circumstances change that would affect our assumptions and estimates. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
The accounting guidance for asset retirement obligations requires that a liability for the present value of estimated future retirement obligations be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its new present value each period, and the capitalized cost becomes part of the depletion base for our oil and gas properties. Holding all other factors constant, if our estimate of asset retirement obligations is revised upward, earnings would decrease due to higher DD&A expense or higher full cost ceiling impairment expense. In addition, the amount of liability recorded for our asset retirement obligation is significantly impacted by our estimate of when the liability will be settled because of the discounting that occurs to reflect the liability at the present value of the future obligation. If we change our estimate of the timing of when each asset retirement obligation is settled by increasing or decreasing the expected settlement date by 3 years, the present value of our asset retirement obligation would decrease $(17.3) million and increase $19.9 million, respectively, at December 31, 2014.
Commodity Derivative Activities
A summary of our outstanding derivative financial instruments is included in Note 8 to the accompanying consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report. Critical accounting estimates associated with our accounting for derivative financial instruments include estimates associated with determining the fair value of those instruments at period end.
The estimated fair value of our swap contracts is primarily based on contractual terms and forward commodity prices. The fair value of our natural gas collars are based on option pricing models which consider the contractual terms, forward commodity prices, and the volatility of natural gas. The credit worthiness of the parties to the derivative contracts also impacts our estimate of the fair value of those contracts. Assuming all other factors are held constant, a 10% change in estimated forward commodity prices would result in an impact of $57.3 million to the estimated fair value of our derivative financial instruments at December 31, 2014. The market price for oil, natural gas, and natural gas liquids is highly volatile. The volatility results in material changes to our reported revenues for a particular period. For example, we recorded $81.3 million, $(58.4) million, and $121.4 million of revenues associated with our derivative financial instruments for the years ended December 31, 2014, 2013 and 2012.
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Stock-Based Compensation
Compensation expense associated with granted stock options and restricted stock is determined based on our estimate of the fair value of those awards at the initial grant or upon modification. The fair value of restricted stock is based on our estimate of the fair value of an unrestricted share of common stock, adjusted for a lack of marketability discount. We utilize the Black-Scholes-Merton option pricing model to measure the fair value of stock options. Key inputs used in the option pricing model include the risk-free interest rate, the fair value and expected volatility of underlying stock, and the expected life of the award. Key assumptions used in measuring stock compensation expense are included in Note 14 to the accompanying consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report.
Our estimate of the fair value of the Companys common stock has a material impact on the determination of stock compensation expense and is difficult to estimate with a high degree of certainty because our common stock is not publically traded and we have not sold any shares of common stock in private transactions subsequent to the initial formation of the Company. We utilize internal models to estimate the fair value of our common stock. Those models consider company specific financial and operational data as well as publically available information about other companies operating within our industry. Equity valuations in our industry can change rapidly with changing market conditions.
The compensation expense we recognize associated with our stock options and restricted stock is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. For the year ended December 31, 2014, a 10% change in the estimated grant date fair value of our outstanding stock options and restricted stock would have changed our stock compensation expense for the period by approximately $5.6 million.
Income Taxes
When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to future audits, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible temporary differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. If we determine that it is more likely than not that our deferred tax assets will not be realized, we must record a valuation allowance to reduce the carrying value of our deferred tax assets. Our assessment includes estimating our future taxable income to determine if our operating loss carryforwards will be utilized before expiration. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating results (which are impacted by prevailing natural gas, oil and NGL prices and our forecasted production levels). In addition, we have certain income tax elections available to us which can increase our taxable income in future periods. Those elections include an election to reduce our current deduction for certain intangible drilling costs.
In addition, we are required to consider the reversal of taxable temporary differences (deferred tax liabilities) when assessing the need for a potential valuation allowance against our deferred tax assets. Our primary taxable temporary difference relates to the difference between the carrying amount of our oil and gas properties and the tax basis of those properties. Our deferred tax liabilities associated with our oil and gas properties are reduced when we record full cost ceiling impairments and periodic depletion expense.
At December 31, 2014, we have deferred tax assets of approximately $515.0 million associated with net operating loss carryforwards totaling $1.5 billion. No valuation allowance was recorded at December 31, 2014 related to our deferred tax assets in part because we have future taxable temporary differences (deferred tax liabilities) that exceed the amount of our deferred tax assets by $765.3 million. We expect the excess of our deferred tax liabilities over our deferred tax assets to be reduced over time as we record full cost ceiling impairments and periodic depletion expense. This is particularly true in periods where we have reduced capital
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budgets as capital expenditures have the potential for increasing our deferred tax liabilities because of tax elections available to us related to certain intangible drilling costs. If we conclude in future periods that it is more likely than not that some of our deferred tax assets will not be realized, we would record a valuation allowance against our deferred tax asset and our deferred tax expense would increase.
Contingent Liabilities
A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters and is required to reasonably estimate recorded expenses when appropriate. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. Actual costs can differ from estimates for many reasons. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. As new information becomes available as a result of activities in such matters, legal or administrative rulings in similar matters, or a change in applicable law, our conclusions regarding the probability of outcomes and potential exposure may change. The impact of subsequent changes to our estimates and accruals may have a material effect on our results of operations in a single period. At December 31, 2014, our accrual for loss contingencies approximated $12.2 million.
Related Party Transactions
For a discussion of related party transactions, see Part III, Item 13Certain Relationships and Related Transactions, and Director Independence and Note 20 to our audited consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report in this report.
Recent Accounting Pronouncements
In August 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-15 Presentation of Financial StatementsGoing Concern. ASU 2014-15 provides guidance around managements responsibility to evaluate whether there is substantial doubt about an entitys ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for our annual period ending after December 15, 2016, and for all annual and interim periods thereafter. Early application is permitted. We have not determined when we will adopt ASU 2014-15 or the impact the new standard will have on our consolidated financial statements. Upon adoption, we will be required to consider whether there are adverse conditions or events that raise substantial doubt about the Companys ability to continue as a going concern within one year after the date that the financial statements are issued and the probability that managements plans will mitigate the adverse conditions or events (if any). Adverse conditions or events would include, but not be limited to, negative financial trends (such as recurring operating losses, working capital deficiencies, or insufficient liquidity), a need to restructure outstanding debt to avoid default, and industry developments (for example commodity price declines and regulatory changes).
In May 2014, the FASB issued ASU 2014-09 Revenue from Contracts with Customers. ASU 2014-09 creates a comprehensive framework for the recognition of revenue. ASU 2014-09 requires an entity to (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 is effective beginning on January 1, 2017 for public entities. We are currently evaluating the potential impact of ASU 2014-09 on our consolidated financial statements.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risk. The term market risk refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures.
Commodity Price Exposure
Our revenues and associated cash flows are dependent on the prices we receive for our crude oil, natural gas and NGLs, which can be volatile because of unpredictable events such as economic circumstances, weather, and political climate, among others. We periodically enter into derivative positions on a portion of our projected oil, natural gas, and NGL production to manage fluctuations in cash flows resulting from changes in commodity prices. All of our market risk sensitive instruments were entered into for risk mitigation purposes, rather than for speculative trading.
At December 31, 2014, we had open natural gas derivatives, crude oil and NGL derivatives in an asset position with a combined fair value of $151.7 million. A ten percent increase in natural gas, crude oil and NGL prices would decrease the asset position by approximately $57.3 million. See Note 8 to our consolidated financial statements, included in Part II, Item 8Financial Statements and Supplementary Data of this report, for notional volumes and terms associated with the Companys derivative contracts.
Interest Rate Risk
Under our RBL Revolver and Second Lien Term Loan, we have debt which bears interest at a floating rate. For the year ended December 31, 2014, the weighted average interest rates on our RBL Revolver and Second Lien Term Loan were 2.1% and 5.1%, respectively. Assuming all revolving loans are fully drawn under the RBL Revolver, each quarter point increase in interest rates would result in a $5.0 million increase in annual interest cost, before capitalization.
Exchange Rate Risk
All of our transactions are denominated in U.S. dollars, and as a result, we do not currently have exposure to currency exchange-rate risks.
Credit Risk
Cash and cash equivalents are not insured above FDIC insurance limits, causing us to be subject to risk. Accounts receivable are primarily due from other companies within the oil and natural gas industry. A portion of the receivables are due from major oil and natural gas purchasers with which we have large natural offsets between revenues and joint interest billings. We do not generally require collateral related to these receivables; however, cash prepayments and letters of credit are requested for accounts with indicated credit risk. All of our derivative exposure is with banks that are lenders under our RBL Revolver or their respective affiliates.
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ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
The Companys audited consolidated financial statements required by this item are included in this report beginning on page F-1.
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
ITEM 9A. | CONTROLS AND PROCEDURES |
Managements Evaluation of Disclosure Controls and Procedures. As required by Rule 15d-15(b) under the Securities Exchange Act of 1934, as amended (the Exchange Act), management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2014. Our disclosure controls and procedures are controls and procedures that we have designed to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to the financial statement preparation and presentation. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2014 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting. We had previously identified a material weakness in our internal control over financial reporting in connection with the preparation of our financial statements for the year ended December 31, 2013 related to the valuation and disclosure of our estimated proved reserves. The material weakness was due to ineffective controls associated with the review of certain underlying data and assumptions used in reserve valuation and disclosures. In response to the previously identified material weakness, we strengthened our internal controls associated with reserve valuation and disclosure for the year ended December 31, 2014 by implementing enhanced management review and data validation procedures associated with underlying data and assumptions used in reserve valuation and disclosures. In addition, we began transacting with our newly implemented enterprise resource planning system in January 2014, which resulted in conforming adjustments to certain internal control processes throughout 2014. Except for the aforementioned changes, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
This Annual Report on Form 10-K does not include a report of managements assessment regarding internal control over financial reporting or an attestation report of Samsons independent registered public accounting firm due to a transition period established by SEC rules for newly public companies. A report of managements assessment regarding internal control over financial reporting is not required until we file our annual report for the year ended December 31, 2015.
ITEM 9B. | OTHER INFORMATION |
None.
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ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
The Boards of Directors of Samson Investment Company and Samson Resources Corporation supervise our management and the general course of our affairs and business operations. Except as otherwise noted below, the individuals comprising the directors and executive officers of Samson Investment Company and Samson Resources Corporation are identical, with each such individual serving in the same capacity for both companies. Unless the context otherwise requires, in this report, references to the Board of Directors, our Board or like terms refer to the Boards of Directors of Samson Investment Company and Samson Resources Corporation collectively.
The following table sets forth certain information regarding the directors and executive officers of Samson Resources Corporation and Samson Investment Company as of March 31, 2015, as well as the committee memberships of the Board of Directors of Samson Resources Corporation. The ages stated below are as of March 31, 2015.
Name |
Age | Office and Position | ||
Randy L. Limbacher |
56 | Chief Executive Officer, President, Director and Member of Executive Committee | ||
Philip W. Cook |
53 | Executive Vice President and Chief Financial Officer | ||
Richard E. Fraley |
57 | Executive Vice President and Chief Operating Officer | ||
Andrew C. Kidd |
52 | Senior Vice President and General Counsel | ||
Julia C. Gwaltney |
43 | Vice PresidentWest Division | ||
Robert W. Jackson |
51 | Vice PresidentInformation Services and Technology | ||
John L. Sharp |
55 | Vice PresidentExploration and New Ventures | ||
Brian A. Trimble |
39 | Vice President and Chief Accounting Officer | ||
Sean C. Woolverton |
45 | Vice PresidentEast Division | ||
Robert V. Delaney, Jr. |
57 | Director and Member of Audit,* Compensation and Executive Committees | ||
Claire S. Farley |
56 | Director and Member of Compensation and Executive Committees | ||
Brandon A. Freiman |
33 | Director and Member of Audit Committee | ||
Toshiyuki Mori |
52 | Director and Member of Compensation and Executive Committees | ||
David C. Rockecharlie |
43 | Director and Member of Audit Committee | ||
Jonathan D. Smidt |
42 | Director and Member of Compensation* and Executive Committees | ||
Akihiro Watanabe |
56 | Director and Member of Audit Committee |
* | Indicates Chairman of the respective Committee of the Board of Directors of Samson Resources Corporation. |
Officers and Directors
Randy L. Limbacher
Mr. Limbacher joined Samson in April 2013. He serves as a director and as Chief Executive Officer and President of Samson Resources Corporation and is a member of the Companys Executive Team. From November 2007 to February 2013, Mr. Limbacher served as Chief Executive Officer, President and director of Rosetta Resources Inc. (Rosetta), a public independent oil and natural gas exploration and development company. Beginning in February 2010, Mr. Limbacher also served as Chairman of the Board of Directors of Rosetta. From February 2013 to April 2013, Mr. Limbacher was a non-officer employee of Rosetta. Prior to joining Rosetta, Mr. Limbacher served as President, Exploration and ProductionAmericas for ConocoPhillips, where he was responsible for all exploration and production activities of that company in the Western Hemisphere. Mr. Limbacher joined ConocoPhillips as part of its April 2006 acquisition of Burlington Resources Inc. (Burlington), an oil and natural gas exploration and production company, where he spent over 20 years. At Burlington, Mr. Limbacher held a series of positions of increasing responsibility, including his role at the time of the acquisition by ConocoPhillips of Executive Vice President, Chief Operating Officer and as a director on the Board of Directors of Burlington. Mr. Limbacher serves on the Board of Directors of CARBO Ceramics Inc. He holds a Bachelor of Science degree in Petroleum Engineering from Louisiana State University.
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As the Chief Executive Officer and President of Samson, Mr. Limbacher provides a management representative on the Board of Directors with knowledge of the day-to-day operations of the Company obtained as a result of his role. Accordingly, he can facilitate the Boards access to timely and relevant information and its oversight of managements strategy, planning and performance. In addition, Mr. Limbacher brings to the Board considerable management and leadership experience and extensive knowledge of the oil and natural gas industry and of our business gained during his over 30-year career in the exploration and production business.
Philip W. Cook
Mr. Cook joined Samson in April 2012. He is Executive Vice President and Chief Financial Officer of Samson Resources Corporation and serves on the Companys Executive Team. From October 2005 to joining Samson in April 2012, Mr. Cook served as Executive Vice President and Chief Financial Officer for Quicksilver Resources, Inc., a public independent oil and natural gas exploration and production company. From September 2011 to April 2012, Mr. Cook also served as a director of Crestwood Gas Services GP LLC, the general partner of Crestwood Midstream Partners LP, a publicly-traded master limited partnership engaged in oil and natural gas midstream operations. Prior to joining Quicksilver Resources, Inc., Mr. Cook served as the chief financial officer for other private energy companies and held various executive positions at Burlington. Mr. Cook holds a CPA and a Bachelors degree in Accounting from New Mexico State University.
Richard E. Fraley
Mr. Fraley joined Samson in July 2013. He is Executive Vice President and Chief Operating Officer of Samson Resources Corporation and serves on the Companys Executive Team. From March 2013 to July 2013, Mr. Fraley served as a managing director for the Energy Mezzanine Opportunities Fund, focusing on upstream and midstream oil and natural gas investment opportunities, for The Carlyle Group, a global alternative asset management firm. Prior to joining The Carlyle Group, Mr. Fraley was an oil and natural gas consultant from July 2007 through February 2013. Beginning in February 1986, Mr. Fraley was with Burlington, where he held officer level positions, including Chief Engineer and Vice President of International Operations. He subsequently oversaw Burlingtons largest operating division in the San Juan Basin, a role which he continued with ConocoPhillips, after its acquisition of Burlington, until June 2007. Prior to Burlington, Mr. Fraley was employed by Superior Oil Company and Mobil Corporation for six years. Mr. Fraley has over 30 years of experience in the oil and natural gas industry and received his Bachelor of Science degree in Geological Engineering from Colorado School of Mines.
Andrew C. Kidd
Mr. Kidd joined Samson in September 2013. He is Senior Vice President and General Counsel of Samson Resources Corporation and serves on the Companys Executive Team. Prior to joining Samson, he served as Partner and General Counsel of Anthem Energy, a private investment manager that develops and operates energy investments, from March 2009 to October 2010 and from October 2011 to August 2013. During October 2010 through September 2011, Mr. Kidd was Senior Vice President and General Counsel of Quantum Utility Generation, LLC, a power generation asset operator. From August 2004 to December 2008, Mr. Kidd was with Constellation Energy Group, Inc. (CEG), serving in various positions, including Deputy General Counsel of CEG, General Counsel of Constellation Energy Resources, the business organization representing CEGs customer supply, global commodities and portfolio management activities, and a member of the Board of Managers of Constellation Energy Partners LLC, a publicly traded exploration and production company that was previously sponsored by CEG. Mr. Kidd also served as a consultant for CEG from December 2008 to March 2009. Earlier in his career, he served as Senior Vice President and Deputy General Counsel of El Paso Corporation and held various officer level positions at Covanta Energy, Inc. Mr. Kidd received his Bachelor of Arts degree from Dartmouth College and his Juris Doctorate degree from the University of Maryland School of Law.
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Julia C. Gwaltney
Ms. Gwaltney joined Samson in April 2014. She is Vice PresidentWest Division of Samson Resources Company and certain of our other operating subsidiaries. Prior to joining Samson, Ms. Gwaltney was with Encana Oil and Gas (USA) Inc., the U.S. subsidiary for a public North American energy producer, for the past 14 years and held a series of positions of increasing responsibility, including Vice President and General Manager, Western Operations. Earlier in her career, Ms. Gwaltney served in various engineering roles with Burlington. Ms. Gwaltney holds a Bachelor of Science degree in Petroleum Engineering from Colorado School of Mines.
Robert W. Jackson
Mr. Jackson joined Samson in May 2012. He is Vice PresidentInformation Services and Technology of Samson Resources Corporation. Prior to joining Samson, he was the Director of Enterprise Architecture & Strategy at Quicksilver Resources, Inc. from May 2007 to May 2012. Earlier in his career, Mr. Jackson held a series of positions of increasing responsibility with Burlington and ConocoPhillips (after its acquisition of Burlington), including Director of Enterprise IT Application. Mr. Jackson received his Bachelor of Science degree in Computer Science from New Mexico State University.
John L. Sharp
Mr. Sharp joined Samson in October 2014. He is Vice PresidentExploration and New Ventures of Samson Resources Company and certain of our other operating subsidiaries. Prior to joining Samson, Mr. Sharp served as Vice PresidentAsset Development of HighMount Exploration & Production LLC, a private oil and gas company, from March 2014 to September 2014. From 2010 to 2013, Mr. Sharp held positions of increasing responsibility with Chesapeake Energy Corporation, a public independent exploration and development oil and natural gas company, including Vice PresidentGeoscience, Southern Division, where he oversaw the geoscience activity of its Haynesville and Barnett Shale assets. From September 2013 to March 2014, Mr. Sharp was on leave after departing Chesapeake. Earlier in his career, he held various technical and managerial positions at other oil and gas companies, including Marathon Oil Corporation and Transfuel Resources Company. Mr. Sharp received his Bachelor of Science and Master of Science degrees from the University of Arkansas.
Brian A. Trimble
Mr. Trimble joined Samson in October 2012. He is Vice President and Chief Accounting Officer of Samson Resources Corporation. From June 2002 through September 2012, Mr. Trimble was with the Tulsa office of Grant Thornton LLP, an independent audit, tax and advisory firm. During that period, he was an audit partner (August 2008 through September 2012) and audit practice leader for the Tulsa office (October 2011 until September 2012). Mr. Trimbles audit clients included many large public energy companies. Mr. Trimble received his Bachelor of Accountancy degree from the University of Oklahoma and is a Certified Public Accountant.
Sean C. Woolverton
Mr. Woolverton joined Samson in November 2013. He is Vice PresidentEast Division of Samson Resources Company and certain of our other operating subsidiaries. From April 2007 to October 2013, Mr. Woolverton held a series of positions of increasing responsibility at Chesapeake Energy Corporation, a public independent exploration and development oil and natural gas company, including Vice President of its Southern Appalachia business unit. Prior to joining Chesapeake Energy Corporation, Mr. Woolverton worked for Encana Corporation, a North American oil and natural gas producer, where he oversaw its Fort Worth Basin development and shale exploration teams in North Texas from April 2006 through April 2007. Earlier in his career, Mr. Woolverton worked for Burlington in multiple senior staff engineering and managing roles. Mr. Woolverton received his Bachelor of Science degree in Petroleum Engineering from Montana Tech.
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Robert V. Delaney, Jr.
Mr. Delaney was named a director of Samson Resources Corporation in December 2011 and is a Partner at Crestview Partners. Mr. Delaney leads the firms energy investing efforts. Prior to joining Crestview Partners in 2007, Mr. Delaney was a Partner at Goldman Sachs & Co. where he served in a variety of leadership positions in private equity and investment banking, including head of the private equity business in Asia and head of the global leveraged finance group. Mr. Delaney received a Master of Business Administration, with high distinction, from Harvard Business School where he was a Baker Scholar. Mr. Delaney also holds a Master of Science degree in Accounting from the Stern School of Business at New York University, and a Bachelor of Arts degree in Economics from Hamilton College, summa cum laude, where he was elected to Phi Beta Kappa. Mr. Delaney also serves on the boards of directors of Select Energy Services, Silver Creek Oil & Gas, Synergy Energy Holdings and CP Energy. The Board of Directors believes Mr. Delaneys senior leadership positions at Crestview Partners and Goldman Sachs & Co., his exceptional educational background and his service on multiple boards of directors provide him the requisite experience necessary to serve as a director.
Claire S. Farley
Ms. Farley was named a director of Samson Resources Corporation in December 2011 and previously served as our interim Chief Executive Officer and President from February 2013 to April 2013. Ms. Farley is a member of KKR Management LLC, the general partner of KKR & Co. L.P., and was a Managing Director of KKRs energy and infrastructure group from November 2011 to December 2012. Prior to joining KKR, from September 2010 to October 2011, Ms. Farley co-founded and was with RPM Energy, LLC, which partnered with KKR to invest in unconventional oil and gas resources. Prior to co-founding RPM Energy, LLC, Ms. Farley was an advisory director at Jefferies Randall & Dewey, the global oil and natural gas industry advisory group at Jefferies Group, Inc., from August 2008 to September 2010 and was Co-President of Jefferies Randall & Dewey from February 2005 to July 2008. Prior to that, Ms. Farley served as Chief Executive Officer of Randall & Dewey, an oil and natural gas asset transaction advisory firm, from September 2002 until its acquisition by Jefferies Group, Inc. in February 2005. Ms. Farley has extensive expertise in oil and natural gas exploration operations, business development and marketing, having spent 18 years at Texaco, Inc. where she held several senior positions, including Chief Executive Officer of Hydro-Texaco, Inc., President of Worldwide Exploration and New Ventures and President of North American Production. She also served as chief executive officer of two start-up ventures, Intelligent Diagnostics Corporation and Trade-Ranger Inc. Ms. Farley holds a Bachelor of Science in Geology from Emory University. Ms. Farley also serves on the board of directors of LyondellBasell Industries, N.V. and FMC Technologies, Inc. and previously served as a director at Encana from 2008 to 2014. The Board of Directors believes that Ms. Farleys successful experience as chief executive officer of several companies, her experiences in exploration, business development and marketing at Texaco, Inc. and her service on multiple boards of directors provide her the requisite experience necessary to serve as a director.
Brandon A. Freiman
Mr. Freiman was named a director of Samson Resources Corporation in May 2013. Mr. Freiman joined KKR in 2007, where he is currently a director in the energy and infrastructure group. During his time at KKR, he has also been involved in several of the firms energy investments, including El Paso Midstream Company, Accelerated Oil Technologies, LLC and Westbrick Energy Ltd., and he has had portfolio company responsibilities for Rockwood Holdings, Inc., a specialty chemical and advanced material company. Prior to joining KKR, Mr. Freiman was with Credit Suisse Securities in its energy investment banking group, where he was involved in a number of merger, acquisition and other corporate transactions. Mr. Freiman currently sits on the board of directors of Energy Future Holdings Corp. He holds a Bachelor of Commerce, with a Joint Honors in Economics and Finance, from McGill University. The Board of Directors believes Mr. Freimans experience at KKR along with his background in investment banking while at Credit Suisse Securities provide him the requisite experience necessary to serve as a director.
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Toshiyuki Mori
Mr. Mori was named a director of Samson Resources Corporation in April 2013. Since October 2011, Mr. Mori has been president and a director of JD Rockies, a wholly-owned subsidiary of ITOCHU. From April 2007 to September 2011, Mr. Mori held a number of positions with ITOCHU, including deputy general manager of its exploration and production department. Prior to joining ITOCHU, Mr. Mori held various management and project development positions with SOJITZ Corporation, Thai Sunrock Company Limited, and NISSHO IWAI Corporation. Mr. Mori earned Bachelor and Master of Science (Economic Geology) degrees from Hokkaido University, Japan. He also attended the Duke Advance Management Program at The Fuqua School of Business Executive Education Program at Duke University. The Board of Directors believes Mr. Moris background in the exploration and production industry at ITOCHU and his prior management experience provide him the requisite experience necessary to serve as a director.
David C. Rockecharlie
Mr. Rockecharlie was named a director of Samson Resources Corporation in December 2011. He is a member of KKR Management LLC, the general partner of KKR & Co. L.P., and he joined KKR in November 2011 as a member of its energy and infrastructure group. Prior to joining KKR, from September 2010 to October 2011, Mr. Rockecharlie co-founded and was with RPM Energy, LLC, which partnered with KKR to invest in unconventional oil and natural gas resources. Prior to founding RPM Energy, LLC, Mr. Rockecharlie was Managing Director and co-head of Jefferies Randall & Dewey, the global oil and natural gas industry advisory group at Jefferies Group, Inc., from June 2008 to June 2010 and Managing Director and head of corporate finance at Jefferies Randall & Dewey from February 2005 to June 2008. Prior to that, Mr. Rockecharlie was a Partner and Managing Director of Randall & Dewey from June 2003 until its acquisition by Jefferies Group, Inc. in February 2005. Earlier in his career, Mr. Rockecharlie was an executive with El Paso Corporation, where he served in various operating and financial roles. Mr. Rockecharlie began his career as an energy investment banker with Donaldson Lufkin & Jenrette and SG Warburg & Co. Mr. Rockecharlie holds an A.B. in Economics, magna cum laude, from Princeton University. The Board of Directors believes Mr. Rockecharlies experience as co-founder of RPM Energy, LLC, his executive experience at El Paso Corporation and his investment banking experience at Donaldson Lufkin & Jenrette and SG Warburg & Co. provide him the requisite experience necessary to serve as a director.
Jonathan D. Smidt
Mr. Smidt was named a director of Samson Resources Corporation in December 2011. Mr. Smidt joined KKR in 2000 where he is currently a senior member of KKRs energy and infrastructure team. Prior to joining KKR, Mr. Smidt was at Goldman, Sachs & Co. in the investment banking group in New York where he spent two years in the energy and power industry group and one year in the mergers and acquisitions group. Mr. Smidt started his career at Ernst & Young in Cape Town, South Africa. He holds a Bachelor of Business Science and a postgraduate diploma in Accounting from the University of Cape Town (South Africa). Mr. Smidt also sits on the boards of Energy Future Holdings Corp., Laureate Education and Westbrick Energy, Ltd. Mr. Smidt also sits on the board of the Mailman School of Public Health at Columbia University. The Board of Directors believes Mr. Smidts energy experience at KKR, including leading KKR Natural Resources, as well as his background in investment banking while at Goldman, Sachs & Co. provide him the requisite experience necessary to serve as a director.
Akihiro Watanabe
Mr. Watanabe was named a director of Samson Resources Corporation in May 2012. Mr. Watanabe is the founder and representative director of GCA Savvian Corporation (GCA), an investment banking firm listed on Tokyo Stock Exchange, and the founder of Global Corporate Advisory, GCAs predecessor company, and he has over 25 years of experience in providing merger and acquisition advisory services both in Japan and overseas. Prior to founding Global Corporate Advisory in 2002, Mr. Watanabe spent 20 years with KPMG, primarily focusing on merger and acquisition advisory and transaction related services for Japanese as well as U.S.
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companies. Mr. Watanabe is a member of the board of directors and the chairman of the audit committee of Ranbaxy Laboratories, Ltd., an Indian pharmaceutical company listed on Bombay Stock Exchange, a visiting professor of Kobe University Business School and he is a certified public accountant. Mr. Watanabe received his Bachelor of Arts in Commerce and Accounting from Chuo University. The Board of Directors believes Mr. Watanabes extensive background in mergers and acquisitions at KPMG and GCA as well as his experience as a board member and chairman of the audit committee of Ranbaxy Laboratories, Ltd. provide him the requisite experience necessary to serve as a director.
Board Structure and Committee Composition
Our Board of Directors currently consists of eight directors, which were appointed by the Principal Stockholders pursuant to the stockholders agreement among Samson Resources Corporation and the Principal Stockholders. For additional information, see Part III, Item 13Certain Relationships and Related Transactions, and Director Independence. Our directors serve until the election of their successor, or until their earlier death, resignation or removal. The Board of Directors of Samson Resources Corporation has an Audit Committee, Compensation Committee and Executive Committee. Our Board of Directors may also establish from time to time other committees that it deems necessary and advisable.
The Board of Directors believes that administering risk management requires the Board as a whole. Our risk management structure is set up in such a way that the executive officers are responsible for the day-to-day risk management responsibilities. Certain of the executive officers attend the meetings of our Board of Directors. The Board of Directors are provided reports on our financial results, the status of our operations, our financial derivatives and other aspects of implementation of our business strategy, with inquiries often made of management regarding specifics within these reports. In addition, at each regular meeting of the Board of Directors, management provides a report of the Companys financial and operational performance, with feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Companys internal auditor, who reports directly to the Audit Committee, and reviews the Companys significant accounting and audit matters with management and our independent auditors.
The Board of Directors is comprised of individuals with backgrounds relevant to the future success of the Company, including extensive experience in energy and finance, as well as backgrounds in operations and marketing. The Board of Directors does not have a formal policy requiring consideration of diversity in board members, nor does it have a formal policy for identifying director nominees. The Board of Directors believes the interests of the Company are best served by individuals with varying backgrounds and expertise in the energy arena. We do not have procedures by which security holders may recommend nominees to our Board of Directors.
Audit Committee
Our Audit Committee consists of Robert Delaney (Chair), Brandon Freiman, David Rockecharlie and Akihiro Watanabe. Among other things, the Audit Committee oversees, reviews, acts on and reports on various auditing, accounting and compliance matters to our Board of Directors. In light of our status as a privately-held company and the absence of a public trading market for shares of our common stock, there are no requirements that we have an independent audit committee and the Board of Directors has not designated any member of the Audit Committee as an audit committee financial expert.
Compensation Committee
Our Compensation Committee consists of Jonathan Smidt (Chair), Robert Delaney, Claire Farley and Toshiyuki Mori. The Compensation Committee has primary responsibility for reviewing and approving the compensation of executive officers, overseeing the Companys benefit plans, and reviewing and making recommendations regarding Board compensation.
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Executive Committee
Our Executive Committee consists of Robert Delaney, Claire Farley, Randy Limbacher, Toshiyuki Mori and Jonathan Smidt. The Executive Committee is responsible for providing rapid access to decision making and confidential discussions for the Board of Directors.
Code of Business Conduct and Ethics
We have adopted a Code of Business Conduct and Ethics for all officers and employees of the Company, including our principal executive, financial and accounting officers. The Code is available on our web site at www.samson.com under Company and Investors. Information on or accessible through our website does not constitute a part of this report.
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ITEM 11. | EXECUTIVE COMPENSATION |
Compensation Discussion and Analysis
Introduction
In May 2012, a compensation committee with authority to recommend or make executive compensation decisions was established by the Board of Directors of Samson Resources Corporation (the Compensation Committee). The following information provides an overview of our compensation objectives and philosophy, describes how our compensation programs are designed and operate with respect to our executive officers for whom compensation is disclosed in the tables below as required by the SEC rules (referred to as the named executive officers) and analyzes important executive compensation decisions with respect to the named executive officers.
2014 Named Executive Officers
Our named executive officers for the fiscal year ended December 31, 2014 were:
Name |
Title |
Start Date | ||
Randy L. Limbacher |
Chief Executive Officer and President | April 2013 | ||
Philip W. Cook |
Executive Vice President and Chief Financial Officer | April 2012 | ||
Richard E. Fraley |
Executive Vice President and Chief Operating Officer | July 2013 | ||
Louis D. Jones |
Executive Vice PresidentBusiness Development, New Ventures and Portfolio Management | August 2013 | ||
Andrew C. Kidd |
Senior Vice President and General Counsel | September 2013 |
From February 26, 2013 to April 17, 2013, we were searching for a new Chief Executive Officer, and Claire S. Farley, a member of KKR Management LLC, the general partner of KKR & Co. L.P., and a director of Samson Resources Corporation and Samson Investment Company since December 2011, acted as our interim Chief Executive Officer and President. Ms. Farley did not receive any compensation for her services as our interim Chief Executive Officer and President, although we provided her with corporate housing in Tulsa, Oklahoma. Our current Chief Executive Officer and President, Randy L. Limbacher, joined the Company on April 18, 2013.
Subsequent to Mr. Limbacher joining the Company in 2013, additional new members of our management team were retained, including our Executive Vice President and Chief Operating Officer, Richard E. Fraley, our Executive Vice PresidentBusiness Development and New Ventures, Louis D. Jones, and our Senior Vice President and General Counsel, Andrew C. Kidd. Mr. Jones employment with the Company terminated effective March 31, 2015.
Executive Compensation Objectives, Philosophy and Process
The elements and amount of compensation for the named executive officers for 2014 are designed based upon the Companys philosophy and practice to attract, retain, motivate, and reward top tier talent in our industry while also creating long-term alignment with our stakeholders interests. Our executive compensation program is designed to provide equitable compensation in a highly competitive environment for talented executives. For 2014, our executive compensation actions largely focused on retention of our named executive officers, as their retention is especially critical due to the challenges in both our industry and our company. To achieve these objectives, during fiscal 2014 we delivered executive compensation through a combination of the following components:
| base salary; |
| annual and special retention cash bonuses; |
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| long-term equity incentive awards and equity-based retention awards; |
| additional benefits, including supplemental executive benefits and perquisites; and |
| other enhanced severance benefits. |
Role of the Board of Directors, Compensation Committee and Executive Officers
Prior to the Acquisition, we were a privately owned company where all executive compensation decisions were made by an executive team. Following the Acquisition and prior to the formation of the Compensation Committee in May 2012, the Board of Directors made all of our executive compensation decisions. Since the formation of the Compensation Committee, all executive compensation decisions have been made by the Compensation Committee with input, as requested, from our human resources department and our Chief Executive Officer, Chief Financial Officer and General Counsel and, starting in 2014, its independent compensation consultant, Frederic W. Cook (F.W. Cook). Our human resources department, Chief Executive Officer and Chief Financial Officer make recommendations to the Compensation Committee for annual base salary and bonus adjustments primarily based on comparative information acquired through industry surveys, as further described below. The Chief Executive Officer evaluates the other named executive officers performance during the year based on their achievement of the goals that were established at the start of the compensation cycle and provides input to the Compensation Committee regarding the other named executive officers base salaries and annual cash bonus amounts. The Compensation Committee makes decisions about the Chief Executive Officers compensation based on his performance during the year, with input from the full Board of Directors. The Chief Executive Officer, Chief Financial Officer and General Counsel are the only named executive officers who have assumed a role in the evaluation, design or administration of our executive officer compensation program. In late 2013, our Compensation Committee engaged F. W. Cook as its independent compensation consultant to provide it with expert analyses, advice and information with respect to our compensation program, including executive officers compensation.
Typically, decisions about the annual base salary adjustments and annual cash bonuses have been made following the end of a compensation cycle, which is based on the close of our fiscal year.
Use of Peer Group Based on Compensation Surveys and Data
In order to improve our compensation analysis, the Compensation Committee considers information from a peer group. The Compensation Committee believes that monitoring executive pay practices at our peer group helps ensure that our executive compensation program and pay levels remain competitive. The peer group is comprised of the companies that we believe that we often compete with for executive talent. The peer group also generally reflects companies that have significant North American oil and gas activities and comparable financial factors such as market capitalization, revenue, assets and enterprise value. Prior to our engagement of F.W. Cook, we used comparative information acquired through industry surveys in formulating recommendations for annual base salary adjustments, bonus payments and equity awards, and our peer group was compiled from the list of companies participating in various industry surveys we utilized when making compensation recommendations. In late 2013, F.W. Cook reviewed the suitability of the peer group being utilized based on operations, market capitalization, revenue, assets and enterprise value and made recommendations for an updated peer group. After considering the recommendations made by F.W. Cook, the peer group was modified by adding 11 new companies (identified with an asterisk in the list below) and removing the following companies: Apache Corporation, Chesapeake Energy Corporation, Continental Resources, Inc., Devon Energy Corporation, Encana Oil & Gas (USA) Inc., EOG Resources, Inc., Linn Operating, Inc., McMoRan Exploration Co., Mewbourne Oil Company, Noble Energy, Inc., Penn Virginia Corporation, PetroQuest Energy, Inc., Pioneer Natural Resources Company, Plains Exploration & Production Company, Talisman Energy USA, Inc. and XTO Energy, Inc.
The updated 2013 peer group was used in making decisions with respect to cash bonuses for services during the fiscal year 2013 that were paid in April 2014. The updated 2013 peer group was also used in making decisions with respect to base salary and annual target bonus modifications during fiscal year 2014.
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The 2013 peer group consisted of the following companies:
| Bill Barrett Corporation* |
| Cabot Oil & Gas Corporation |
| Cimarex Energy Co. |
| Concho Resources, Inc. (COG Operating LLC)* |
| Denbury Resources, Inc.* |
| EXCO Resources, Inc.* |
| Forest Oil Corporation |
| Laredo Petroleum Holdings, Inc.* |
| Newfield Exploration Company |
| Oasis Petroleum, Inc.* |
| QEP Resources, Inc. |
| Range Resources Corporation |
| SandRidge Energy, Inc.* |
| SM Energy Company |
| Southwestern Energy Company |
| Stone Energy Corporation* |
| Swift Energy Company* |
| Ultra Petroleum Corporation* |
| Whiting Petroleum Corporation* |
| WPX Energy, Inc. |
Assessment of Individual and Company Performance
We generally conduct annual performance reviews of each of our senior executives during the first quarter following the end of the respective compensation cycle. The manager and executive review the goals and objectives that were established at the start of that compensation cycle and assess the degree of achievement. We also assess the overall performance and organizational impact of each executive as well as their future potential in the Company. The performance goals and objectives set at the start of the compensation cycle vary from individual to individual, although there are shared goals among the executives, and they generally relate to operational or management goals relating to the persons area of responsibility within the organization.
Due to the changes in our management team during 2013, our named executive officers did not have pre-determined goals that were communicated to them at the beginning of fiscal year 2013 or at the time of hire. Rather, their annual bonus amounts were determined based on our Chief Executive Officers (or, in the case of the Chief Executive Officer, the Compensation Committees) subjective evaluation of their performance. For 2014, the Chief Executive Officer communicated individual goals to the other named executive officers in the first quarter of the fiscal year. For further discussion, see Elements of Compensation2014 Bonuses.
In late 2013, the Company hired F.W. Cook, a nationally recognized consulting firm specializing in executive compensation, to assist the Company in setting the total compensation of the executives at levels between the 50th and 75th percentile of our peers and to more consistently align the components and terms of the
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total compensation packages among our executives based on their respective positions. As of result of the information presented by F.W. Cook and the then-recent fair market value determination of our common stock made by our Board of Directors, we made various executive compensation actions in February and March 2014, including, among other things, the following: i) implemented a moderate increase in the base salary of the executives, ii) implemented a moderate increase in the annual target bonus for Mr. Kidd, (iii) granted stock and options to certain named executive officers, iv) repriced outstanding stock options held by employees, including the named executive officers, to reduce the exercise price per share to $2.50, v) amended the vesting terms of restricted stock awards held by all employees, with the exception of Mr. Limbacher, to provide that (a) all restricted stock awards will immediately vest upon a change-in-control and a qualifying termination of employment and (b) the 2013 restricted stock awards will vest annually in four equal tranches beginning in 2015, and (vi) offered to repurchase shares of our common stock at a price per share equal to the initial cost basis of such shares, which was more than the then current fair market value, from current employees who had previously purchased shares. For additional information on these compensation actions, please see Elements of CompensationLong-Term Equity Incentive Awards and Award Modifications and Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 TableTerms of Restricted Stock Awards.
In August 2014, the Compensation Committee approved a number of executive compensation actions to retain our executives, including, but not limited to: (i) approving officer retention letter agreements (Officer Retention Letter Agreements) which provide for, among other things, (a) a retention award for officers remaining employed with the Company through September 1, 2015, (b) accelerated vesting of outstanding equity held by the officers, and (c) special temporary put and call rights on restricted stock held by officers; (ii) adopting the Samson Resources Corporation Voluntary Severance Plan for Officers (the Officer Voluntary Severance Plan); (iii) awarding officers 100% of their individual annual target bonuses for 2014 and accelerating payment of those bonuses to January 9, 2015; and (iv) awarding officers a one-time special bonus in an amount equal to 100% of their individual annual target bonus. For further discussion, see Potential Payments Upon a Termination or a Change of ControlOfficer Retention Letter Agreements. These actions were made to (i) help ensure the continued services of our executives for the execution of certain portfolio management activities and other strategic transactions then-contemplated by the Company; (ii) increase the cash component of our executives total compensation package, in recognition of the uncertainties relating to the future realized value of their equity awards due, in part, to the absence of a public market for our common stock; and (iii) generally increase the retentive nature of the executives total compensation package in light of the Companys substantial indebtedness.
In March 2015, the Company entered Release Payment Letter Agreements with officers which release the Company from the obligations under the Officer Retention Letter Agreements and Officer Voluntary Severance Plan, with the exception of the accelerated vesting of outstanding equity and COBRA reimbursement provisions. For further discussion, see Recent Compensation Actions in 2015.
Elements of Compensation
Base Salary
Base salaries are intended to provide a market competitive level of fixed compensation that recognizes the responsibilities, skills, capabilities, experience, and leadership of each executive officer. Base salaries are tiered to be competency and tenure based. Base salaries of employees, including our executive officers, are generally reviewed at least annually, typically during the first quarter after conducting the performance reviews described above, and decisions about base salary adjustments are made at that time.
On February 13, 2014, the Compensation Committee approved upward adjustments to the base salaries of the named executive officers, effective April 1, 2014. The 2014 levels of base salaries reflected the increase in base salary in the industry in general at the time and, with the exception of Mr. Limbacher, were intended to
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approximate between the 50th percentile and the 75th percentile of the comparable positions in the peer group used with respect to fiscal years 2013 and 2014, which the Compensation Committee believed was important to retain top tier talent in an intensely competitive industry. For further discussion, see Assessment of Individual and Company Performance.
The base salaries of the named executive officers in effect during fiscal year 2014 were:
Name |
Base Salary (in effect from January 1, 2014March 31, 2014) |
Base Salary (in effect from April 1, 2014December 31, 2014) |
||||||
Randy L. Limbacher |
$ | 800,000 | $ | 830,000 | ||||
Philip W. Cook |
$ | 530,006 | $ | 550,000 | ||||
Richard E. Fraley |
$ | 530,004 | $ | 550,000 | ||||
Louis D. Jones |
$ | 475,008 | $ | 495,000 | ||||
Andrew C. Kidd |
$ | 400,008 | $ | 415,000 |
The base salaries of the named executive officers shown in the Summary Compensation Table below reflect the base salaries actually earned by them during the fiscal years ending December 31, 2014, 2013 and 2012 as indicated in the table.
2014 Bonuses
Under the terms of Mr. Limbachers employment agreement, his target annual award opportunity under the annual bonus plan is 100% of his base salary. With respect to annual target bonuses for performance during 2014, Messrs. Cook, Fraley, Jones and Kidd were each informed that their respective target annual bonus amount was 100% of their respective base salary. Pursuant to recommendations made by our Chief Executive Officer, Mr. Limbacher, in August 2014, the Compensation Committee approved the amount of annual bonuses to be paid to the other named executive officers at target level on an expedited basis. Mr. Limbachers recommendations were aimed at retaining the executives into the third quarter of 2015 and were based on the strategic direction of the Company and the short-term value of equity awards owned by the executives as well as his subjective evaluation of each such officers performance during 2014. The Compensation Committee approved his recommendations. Similarly, in August 2014, the Compensation Committee determined the amount of Mr. Limbachers annual bonus was also to be paid at target based on the same considerations. The Compensation Committee and Mr. Limbacher did not rely on any objective or quantitative performance metrics in evaluating the named executive officers annual bonus amounts. The annual bonuses with respect to fiscal year 2014 were paid on January 9, 2015.
Additionally, in August 2014, the Compensation Committee approved a special one-time cash bonus (Special Bonus) for the named executive officers of the Company in an amount equal to the individual officers 2014 annual target bonus, as described in the preceding paragraph. The Compensation Committee granted the Special Bonuses as an additional retention element for the officers of the Company. In order to receive the Special Bonus, officers were required to execute a bonus agreement which specified that the Special Bonus was a one-time bonus not to be included in any calculation of a future bonus amount. The Special Bonuses were also paid to officers on January 9, 2015.
Long-Term Equity-Based Incentive Awards and Award Modifications
In connection with the Acquisition, we adopted the Samson Resources Corporation 2011 Stock Incentive Plan (the 2011 Plan) for our employees, directors, and certain other service providers and independent contractors. The Compensation Committee may grant stock options, stock appreciation rights, restricted stock, restricted stock units or other stock-based awards under the 2011 Plan. In May 2013, we amended the 2011 Plan to increase the number of shares available for issuance.
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Our long-term incentive (LTI) awards for executive officers are granted in the form of stock options and restricted stock. The Compensation Committee believes that LTI awards closely align our managements interest with those of our stockholders and incentivizes our management employees to remain in our service.
In late 2013, the Company hired F.W. Cook, a nationally recognized consulting firm specializing in executive compensation, to assist the Company in setting the total compensation of the executives at levels between the 50th and 75th percentile of our peers and to more consistently align the components and terms of the total compensation packages among our executives based on their respective positions. As of result of the information presented by F.W. Cook and the then-recent fair market value determination of our common stock made by our Board of Directors, on March 24, 2014,
| we granted Mr. Fraley 800,000 stock options, as described in more detail under Terms of Option Awards2014 Options; |
| we granted Mr. Limbacher 2,500,000 shares of restricted stock, as described in more detail under Terms of Restricted Stock Awards Restricted Stock Granted to Mr. Limbacher; and |
| we granted 1,300,000, 1,450,000, 600,000 and 1,000,000 shares of restricted stock to each of Messrs. Cook, Fraley, Jones and Kidd, respectively, as described in more detail under Terms of Restricted Stock Awards Restricted Stock Granted to Messrs. Cook, Fraley, Jones and Kidd. |
As part of a review of our executive compensation and employee benefit arrangements on behalf of and under the supervision of our board of directors and due to the previously granted options having a fair market value below their exercise price, in fiscal year 2014 we determined that modifying all outstanding options by reducing the per-share exercise price may be better suited than the original options to meet our objectives to attract, motivate, retain and reward talented and experienced individuals. In addition, we believed the repricing would align executive compensation with achievement of our overall business goals, adherence to our core values and stakeholder interests. Therefore, on March 24, 2014, we reduced the exercise price of all outstanding options, including those held by our named executive officers (other than Mr. Limbacher), to $2.50. All of the option holders were required to enter into an amendment to their existing option agreement that reflected the repricing.
At the same time as the general repricing described above, we amended Mr. Limbachers employment agreement, to provide for (i) the forfeiture by Mr. Limbacher of 250,000 stock options with an exercise price of $4.00 per share, (ii) the forfeiture by Mr. Limbacher of 250,000 stock options with an exercise price of $5.00 per share, (iii) the repricing of 10,000,000 of his stock options with an initial exercise price of $7.50 per share to an exercise price of $2.50 per share (consistent with the repricing for all employees), and (iv) an amended vesting schedule for his 2013 restricted stock awards which will now vest annually in four equal tranches beginning in April 2015.
Severance and Retention Benefits
The employment agreement we entered into with Mr. Limbacher and the special agreements we entered into with Messrs. Cook, Fraley and Jones at the time of their respective hire provide for severance payments and benefits under certain termination circumstances. The terms of these agreements and the severance payments and benefits are described more fully under Potential Payments Upon a Termination or a Change of Control.
On March 24, 2014, the Compensation Committee adopted the Samson Resources Corporation Change in Control Severance Plan for Officers (the Change in Control Severance Plan), effective as of January 1, 2014, pursuant to which officers will receive cash compensation and certain other benefits in the event of a change-in-control and a qualifying termination of employment. All of the named executive officers, except Mr. Limbacher, are eligible for severance under the Change in Control Severance Plan. The terms of these severance payments and benefits are described more fully under Potential Payments Upon a Termination or a Change of Control.
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Also in March 2014, the Compensation Committee approved amendments to the vesting terms of the restricted stock awards held by employees, including our named executive officers, except Mr. Limbacher, which provide that (i) all restricted stock awards will immediately vest upon a change-in-control and a qualifying termination of employment and (ii) the 2013 restricted stock awards will now vest annually in four equal tranches beginning in 2015. The Compensation Committee also approved an agreement with Mr. Jones permitting him, in the event of retirement or permanent disability, to retain the then vested portion of any restricted stock or stock options (which may be exercised at any time during the term of such options).
In August 2014, the Compensation Committee approved the entry into the Officer Retention Letter Agreements with the named executive officers, which provide for participation in the Officer Voluntary Severance Plan for named executive officers who remain with the Company through September 1, 2015, but choose to terminate employment as of that date. The Officer Retention Letter Agreements also provide for certain severance payments and benefits for officers in the event the Company terminates the officers employment without Cause prior to September 1, 2015. The terms of the Officer Retention Letter Agreements and the Officer Voluntary Severance Plan were finalized in November 2014, and are described more fully under Potential Payments Upon a Termination or a Change of Control. The Compensation Committee believes that severance arrangements are necessary to attract and retain the talent necessary for our long-term success. For further discussion see, Assessment of Individual and Company Performance. In March 2015, the Company entered Release Payment Letter Agreements with officers which release the Company from the obligations under the Officer Retention Letter Agreements and Officer Voluntary Severance Plan, with the exception of the accelerated vesting of outstanding equity and COBRA reimbursement provisions, which remain in effect. For further discussion, see Recent Compensation Actions in 2015.
Additional Benefits
Health and Welfare Benefits. Our named executive officers are eligible to participate in all of our employee health and welfare benefit arrangements on the same basis as other employees (subject to and in accordance with applicable laws). These arrangements include: medical, dental, vision, life and accidental death and dismemberment insurance, as well as short and long term disability benefits. These benefits are provided to ensure that we are able to competitively attract and retain employees, including our named executive officers.
In addition, in 2014 our named executive officers were eligible to participate in Execucare, a special medical plan available to our officers that reimburses the participant for all of his or her premium costs and out-of-pocket medical expenses. The Execucare plan was terminated effective December 31, 2014.
Retirement Benefits. We maintain an employee retirement savings plan through which employees may save for retirement or future events on a tax-advantaged basis. We currently provide matching contributions under our 401(k) plan up to 6% of an employees base salary plus bonus, as well as providing an additional 2% non-matching contribution. Employees become fully vested in the Companys contributions after five years of service. Participation is at the discretion and direction of each individual employee, and our named executive officers participate in the plan on the same basis as all other employees.
We also provide certain other benefits described below to our named executive officers, which are not tied to any performance criteria. Rather, these benefits are intended to support objectives related to the attraction and retention of highly skilled executives.
Use of Corporate Aircraft. Prior to May 2013, Company officers were eligible to use the corporate aircraft for personal use on a limited basis. Subsequent to May 2013, our employees personal use of the corporate aircraft has been limited to exceptional circumstances, such as medical emergencies, and spousal travel on trips related to business which, under the SEC rules, may not be considered to be directly and integrally related to our business.
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Relocation Benefits. To facilitate the relocation and hiring of officers and other key personnel, we provide relocation benefits which generally include payments to prevent a loss on the sale of residence and to cover reasonable costs related to the move.
Other Perquisites. We also provide certain other immaterial perquisites, such as personal use of company vehicles, dependent education assistance, financial planning reimbursement and private club dues, as further described in the footnote to the All Other Compensation column in the Summary Compensation Table below.
Recent Compensation Actions in 2015
In March 2015, the Company entered Release Payment Letter Agreements with officers remaining employed with the Company after April 1, 2015, including the named executive officers. The Release Letter Agreements release the Company from the obligations under the November 14, 2014 Officer Retention Agreements and the Voluntary Severance, with the exception of the accelerated vesting of outstanding equity and COBRA reimbursement provisions. The Release Letter Agreements provide that the Company shall pay to the officers a one-time lump sum payment equal to one-half of the value of the Retention Award provided in the Officer Retention Letter Agreements (i.e., an amount equal to the officers 2015 base salary and annual target bonus) (Release Payment). The officer must sign a waiver and release agreement in exchange for the Release Payment.
Additionally, in March 2015, the Compensation Committee approved a new incentive compensation program that replaces the Companys existing short- and long-term incentive arrangements. Effective immediately, the named executive officers shall be eligible to receive quarterly cash bonuses based on the achievement of applicable vesting conditions established by the Compensation Committee, which for quarters beginning April 1, will be one or more objective performance criteria.
Summary Compensation Table
The following table provides summary information concerning compensation paid or accrued by us to or on behalf of our named executive officers, for services rendered to us during each of the years presented.
Name and Principal Position |
Year | Salary ($) |
Bonus ($)(2) |
Stock Awards ($)(3) |
Option Awards ($)(3) |
All Other Compensation ($)(4) |
Total ($) |
|||||||||||||||||||||
Randy L. Limbacher, Chief |
2014 | 822,500 | 1,660,000 | 5,325,000 | 5,558,456 | 46,730 | 13,412,686 | |||||||||||||||||||||
Executive Officer and President(1) |
2013 | 561,026 | 750,000 | 17,000,000 | 38,236,156 | 72,730 | 56,619,912 | |||||||||||||||||||||
Philip W. Cook, Executive Vice |
2014 | 545,002 | 1,100,000 | 2,769,000 | 788,432 | 158,610 | 5,361,044 | |||||||||||||||||||||
President and Chief Financial Officer(1) |
2013 | 530,006 | 650,000 | 1,360,000 | 1,948,675 | 328,218 | 4,816,899 | |||||||||||||||||||||
2012 | 359,170 | 915,100 | | 2,880,000 | 1,023,607 | 5,177,877 | ||||||||||||||||||||||
Richard E. Fraley, Executive Vice |
2014 | 545,012 | 1,100,000 | 3,088,500 | 1,619,270 | 69,752 | 6,422,534 | |||||||||||||||||||||
President and Chief Operating Officer(1) |
2013 | 226,950 | 550,000 | 1,360,000 | 3,666,597 | 122,808 | 5,926,355 | |||||||||||||||||||||
Louis D. Jones, Executive Vice |
2014 | 490,002 | 990,000 | 1,278,000 | 1,099,981 | 42,468 | 3,900,451 | |||||||||||||||||||||
PresidentBusiness Development and New Ventures(1) |
2013 | 194,571 | 250,000 | 1,360,000 | 3,108,892 | 5,974 | 4,919,437 | |||||||||||||||||||||
Andrew C. Kidd, Senior Vice |
2014 | 411,253 | 830,000 | 2,130,000 | 544,015 | 103,284 | 4,018,552 | |||||||||||||||||||||
President and General Counsel(1) |
2013 | 125,003 | 170,000 | | 2,835,348 | 268,770 | 3,399,121 |
(1) | Messrs. Limbacher, Cook, Fraley, Jones and Kidd each commenced employment with us, effective April 18, 2013, April 16, 2012, July 29, 2013, August 5, 2013 and September 9, 2013, respectively. Accordingly, 2012 salaries (in the case of Mr. Cook) and 2013 salaries (in the case of Messrs. Limbacher, Fraley, Jones and Kidd) were pro-rated, as applicable. 2014 salaries represent amounts actually paid during the year and reflect increases as of April 1, 2014. |
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(2) | Mr. Cooks 2012 amount represents a special hiring bonus of $350,000 he received upon the commencement of his employment, a pro-rated annual discretionary bonus of $300,000 he received in November 2012 under the terms of his special agreement with us and the bonus he earned for his services during the six-month period from July 1, 2012 to December 31, 2012, which was paid in April 2013. The amount for 2014 for each of our named executive officers represents the annual bonus earned by each such officer for services during the year ended December 31, 2014, as well as their special bonuses, which were paid in January 2015. See Compensation Discussion and AnalysisElements of Compensation2014 Bonuses. |
(3) | The dollar amounts represent the aggregate grant date fair value of restricted stock awards and option awards, respectively, granted in the indicated fiscal year. The grant date fair value of a restricted stock award and an option award, respectively, is measured in accordance with FASB ASC Topic 718 utilizing the assumptions discussed in Note 14 to our audited consolidated financial statements included in Part II, Item 8Financial Statements and Supplementary Data of this report. On March 24, 2014, we repriced outstanding stock options held by each of our named executive officers, other than Mr. Limbacher, to reduce the exercise price per share to an exercise price of $2.50 per share. Additionally, on March 24, 2014, Mr. Limbacher forfeited 250,000 stock options with an exercise price of $4.00 per share and 250,000 stock options with an exercise price of $5.00 per share and the Company the repriced 10,000,000 of his stock options with an initial exercise price of $7.50 per share to an exercise price of $2.50 per share. The incremental fair value with respect to such repriced awards, calculated pursuant to ASC Topic 718 as of the repricing, is included for each named executive officer in the 2014 Option Awards column. For a discussion of specific restricted stock awards and option awards granted during 2014, see Grants of Plan-Based Awards in Fiscal 2014 below and the narrative discussion that follows. |
(4) | All Other Compensation for the named executive officers for 2014 includes the following: |
401(k) Contribution (a) |
Personal Use of Vehicle (b) |
Group Term Life Insurance Premiums (c) |
Personal Use of Aircraft (d) |
Financial Planning Assistance (e) |
Dependent Education Assistance (f) |
Club Dues (g) |
Tax Gross- Up (h) |
Relocation Benefits (i) |
Execucare (j) |
Parking (k) |
Stock Repurchase (l) |
|||||||||||||||||||||||||||||||||||||
R. Limbacher |
$ | 20,800 | $ | | $ | 4,902 | $ | 821 | $ | | $ | | $ | 9,730 | $ | 9,390 | $ | | $ | 187 | $ | 900 | $ | | ||||||||||||||||||||||||
P. Cook |
$ | 20,800 | $ | 3,955 | $ | 2,622 | $ | 4,166 | $ | | $ | | $ | 8,918 | $ | 13,455 | $ | | $ | 3,794 | $ | 900 | $ | 100,000 | ||||||||||||||||||||||||
R. Fraley |
$ | 20,800 | $ | | $ | 4,902 | $ | 7,203 | $ | | $ | 13,200 | $ | | $ | 10,224 | $ | 2,000 | $ | 5,513 | $ | 5,910 | $ | | ||||||||||||||||||||||||
L. Jones |
$ | 20,800 | $ | | $ | 7,368 | $ | 113 | $ | 2,800 | $ | | $ | 50 | $ | 604 | $ | | $ | 9,833 | $ | 900 | $ | | ||||||||||||||||||||||||
A. Kidd |
$ | 20,800 | $ | 2,670 | $ | 2,133 | $ | | $ | | $ | | $ | 9,159 | $ | 11,561 | $ | 47,528 | $ | 8,533 | $ | 900 | $ | |
(a) | Represents a matching contribution to the executives 401(k) plan. |
(b) | Represents incremental costs associated with the personal use of a company car. |
(c) | Represents payments of premiums for a group life insurance policy. |
(d) | Represents incremental costs associated with the personal use of corporate aircraft. The incremental cost was calculated by multiplying the personal aviation hours used by the executive officer and/or his guests by the average variable cost per hour of $1,900 of operating the corporate aircraft. The average variable cost per hour includes costs relating to fuel, trip-related maintenance, inspections, crew travel expenses, contracted crew services, trip-related fees and storage costs, on-board catering, aircraft supplies and deadhead flights. In addition, a cost per hour of $25, representing on-board catering, was included for any personal hours related to guests accompanying an executive officer on a business trip. |
(e) | Represents actual cost of financial planning assistance provided to our executives. |
(f) | Represents the actual cost of education assistance provided by us to employees dependents. |
(g) | Represents payments of private club dues and expenses on behalf of the executives. |
(h) | Represents tax gross-up of imputed income relating to personal use of the corporate aircraft, club dues and relocation benefits, as well as certain other benefits that are provided generally to all salaried employees. |
(i) | Represents relocation benefits provided to each of Messrs. Fraley and Kidd in connection with his hire. These relocation benefits included our standard relocation benefits. The incremental costs were calculated based on the invoice amounts provided to us. |
(j) | Represents premiums and claims paid under a supplemental healthcare plan for our executives. |
(k) | Represents vehicle parking fees paid for our executives. |
(l) | Represents the amount paid in excess of the fair market value for the repurchase of shares of our stock. |
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Grants of Plan-Based Awards in Fiscal 2014
The following table provides supplemental information relating to grants of plan-based awards in fiscal 2014.
Name |
Approval Date |
Grant Date |
All Other Stock Awards: Number of Shares of Stock or Units (#) |
All Other Option Awards: Number of Securities Underlying Options (#) |
Exercise or Base Price of Option Awards ($/Share) |
Grant Date Fair Value of Stock and Option Awards |
||||||||||||||||||
Randy L. Limbacher |
3/24/14 | 3/24/14 | 2,500,000 | | $ | 5,325,000 | ||||||||||||||||||
3/24/14 | (1) | 3/24/14 | 10,000,000 | $ | 2.50 | $ | 5,558,456 | (1) | ||||||||||||||||
Philip W. Cook |
3/24/14 | 3/24/14 | 1,300,000 | | $ | 2,769,000 | ||||||||||||||||||
3/24/14 | (1) | 3/24/14 | (1) | 1,200,000 | $ | 2.50 | $ | 471,936 | (1) | |||||||||||||||
3/24/14 | (1) | 3/24/14 | (1) | 1,200,000 | $ | 2.50 | $ | 316,496 | (1) | |||||||||||||||
Richard E. Fraley |
3/24/14 | 3/24/14 | 1,450,000 | $ | 3,088,500 | |||||||||||||||||||
3/24/14 | 3/24/14 | 800,000 | $ | 2.50 | $ | 846,960 | ||||||||||||||||||
3/24/14 | (1) | 3/24/14 | (1) | 1,200,000 | $ | 2.50 | $ | 316,496 | (1) | |||||||||||||||
3/24/14 | (1) | 3/24/14 | (1) | 1,200,000 | $ | 2.50 | $ | 455,814 | (1) | |||||||||||||||
Louis D. Jones |
3/24/14 | 3/24/14 | 600,000 | | $ | 1,278,000 | ||||||||||||||||||
3/24/14 | (1) | 3/24/14 | (1) | 1,250,000 | $ | 2.50 | $ | 633,067 | (1) | |||||||||||||||
3/24/14 | (1) | 3/24/14 | (1) | 750,000 | $ | 2.50 | $ | 466,914 | (1) | |||||||||||||||
Andrew C. Kidd |
3/24/14 | 3/24/14 | 1,000,000 | | $ | 2,130,000 | ||||||||||||||||||
3/24/14 | (1) | 3/24/14 | (1) | 1,200,000 | $ | 2.50 | $ | 316,496 | (1) | |||||||||||||||
3/24/14 | (1) | 3/24/14 | (1) | 600,000 | $ | 2.50 | $ | 227,519 | (1) |
(1) | On March 24, 2014, we repriced outstanding stock options held by each of our named executive officers, other than Mr. Limbacher, to reduce the exercise price per share to an exercise price of $2.50 per share. Additionally, on March 24, 2014, Mr. Limbacher forfeited 250,000 stock options with an exercise price of $4.00 per share and 250,000 stock options with an exercise price of $5.00 per share and the Company the repriced 10,000,000 of his stock options with an initial exercise price of $7.50 per share to an exercise price of $2.50 per share. The incremental fair value with respect to such repriced awards, calculated pursuant to ASC Topic 718 as of the repricing, is included for each named executive officer. For further discussion, see Elements of CompensationLong-Term Equity Incentive Awards and Award Modifications. |
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 Table
Employment Agreement with Randy L. Limbacher
We entered into an employment agreement with Randy L. Limbacher, effective as of April 18, 2013, for an initial five-year term. Commencing on the fifth anniversary of the effective date and on each anniversary thereafter, the agreement automatically renews for an additional one-year period, unless we or Mr. Limbacher provide written notice requesting that the agreement not be extended at least 60 days prior to the agreements renewal date. The agreement provides that Mr. Limbacher serves as our Chief Executive Officer and President.
Pursuant to this agreement, Mr. Limbacher is entitled to receive a base annual salary of $800,000, subject to annual upward adjustments, at the discretion of the Board of Directors, and he will participate in any annual cash bonus plan applicable to his position that may be adopted by us from time to time. His target annual bonus will be 100% of his base salary, subject to such other terms, conditions and restrictions as may be established by the Board of Directors or the Compensation Committee. Mr. Limbacher is also entitled to participate in the 2011 Plan. In connection with entering into the employment agreement, he was granted (i) options to purchase 6,250,000 shares of our common stock at an exercise price equal to $4.00 per share, (ii) options to purchase 6,250,000 shares of our common stock at an exercise price equal to $5.00 per share, (iii) options to purchase
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17,500,000 shares of our common stock at an exercise price equal to $7.50 per share, and (iv) 5,000,000 shares of restricted common stock.
Mr. Limbachers employment agreement was amended on April 1, 2014 to provide for (i) the forfeiture by Mr. Limbacher of 250,000 stock options with an exercise price of $4.00 per share, (ii) the forfeiture by Mr. Limbacher of 250,000 stock options with an exercise price of $5.00 per share, (iii) the repricing of 10,000,000 of his stock options with an initial exercise price of $7.50 per share to an exercise price of $2.50 per share and (iv) an amended vesting schedule for his 2013 restricted stock awards to vest annually in four equal tranches beginning in April 2015.
Pursuant to the terms of the Officer Retention Letter Agreement with Mr. Limbacher, all of the stock and options awarded to Mr. Limbacher as of November 14, 2014 will now fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015.
Mr. Limbacher is entitled to participate in all employee benefits plans and arrangements that are generally made available to our executives and perquisites and other benefits that are generally made available to our executives or to him in particular.
Mr. Limbachers employment agreement also provides for severance payments and benefits as further described under Potential Payments Upon a Termination or a Change in ControlMr. Limbachers Employment Agreement.
Special Agreement with Philip W. Cook
We entered into a special agreement with Philip W. Cook, our Executive Vice President and Chief Financial Officer, on April 16, 2012. The agreement provides for severance payments and benefits as further described under Potential Payments Upon a Termination or a Change in ControlMr. Cooks Special Agreement.
Special Agreements with Richard E. Fraley and Louis D. Jones
We entered into special agreements with Richard Fraley and Louis D. Jones, effective August 1, 2013 and August 5, 2013, respectively. Messrs. Fraleys and Jones special agreements provide for severance payments and benefits as further described under Potential Payments Upon Termination or a Change in ControlSpecial Agreements with Messrs. Fraley and Jones.
Terms of Option Awards
2012 Options
The following describes the terms of the options granted to Mr. Cook in 2012.
Vesting Terms. Originally, the options vested in four equal annual installments beginning on December 21, 2012, subject to Mr. Cooks continued employment with us, but would become fully vested upon a change in control that occurs during employment with us. Twenty-five percent of the shares subject to the option that would otherwise vest on the next vesting date will vest upon the executives termination of employment by the executive for good reason or due to death or disability. Pursuant to the terms of the Officer Retention Letter Agreements effective November 14, 2014, all of the options awarded to executives as of November 14, 2014 will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. If the executives employment is terminated by us for cause, both the vested and unvested options will be forfeited. A change of control is defined under our 2011 Plan as (i) the sale of all or substantially all of our assets to any person other than KKR, ITOCHU and certain of
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our other investors or their respective affiliates or (ii) a merger, recapitalization or sale of equity interests or voting power that results in any person other than KKR, ITOCHU and certain of our other investors or their respective affiliates owning more than 50% of the equity interests or voting power of Samson Resources Corporation, Samson Investment Company or any resulting company (as applicable). Effective September 1, 2015, change of control will be defined by our 2011 Plan as (i) the sale of all or substantially all of our assets, as owned as of September 1, 2015 and not then contemplated to be sold, to any person other than KKR, ITOCHU and certain of our other investors or their respective affiliates or (ii) a merger, recapitalization or sale of equity interests or voting power that results in any person other than KKR, ITOCHU and certain of our other investors or their respective affiliates owning more than 50% of the equity interests or voting power of Samson Resources Corporation, Samson Investment Company or any resulting company (as applicable).
Liquidity Program. Beginning in 2016 and each calendar year thereafter, each executive who is still employed with us at such time and each executive who (i) was terminated by us without cause, (ii) resigns for good reason or (iii) resigns without good reason on or after June 21, 2015, has the right to cause us to purchase all or any portion of stock issuable upon exercise of options then held by such executive; provided, however, the executive may not offer to sell in any one calendar year more than 25% of the stock issuable upon exercise of the total amount of options granted to the executive in 2012 under the 2011 Plan.
Option Call Rights. If the executives employment is terminated by us without cause, the executive resigns for good reason, the executives employment terminates due to death or disability, or the executive resigns without good reason on or after June 21, 2015, in each case, we have the right to purchase from the executive all or any portion of vested options then held by the executive at a price equal to the excess, if any, of the fair market value of the underlying shares, over the exercise price for such options and all outstanding unvested options will terminate without payment. Additionally, pursuant to the Officer Retention Letter Agreements, beginning September 2, 2015 we were to have temporary rights to repurchase from the executive all or any portion of vested options at a price equal to the excess, if any, of the fair market value of the underlying shares. The call rights under the officer Retention Letter Agreements were terminated pursuant to the Release Letter Agreements to be effective April 1, 2015. For further discussion see Officer Retention Letter Agreements.
Option Put Rights. If the executives employment is terminated by reason of death or disability, the executive has the right to cause us to all of the vested options in an amount equal to the sum of the excess, if any of the fair market value on the repurchase calculation date over the exercise price. If such sum is zero or a negative number, the options automatically terminate without payment. Additionally, pursuant to the Officer Retention Letter Agreements, options owned by the executive are subject to temporary out rights commencing September 2, 2015. The put rights under the Officer Retention Letter Agreements were terminated pursuant to the Release Letter Agreements to be effective March 31, 2015. For further discussion on the temporary put rights, see Potential Payments Upon a Termination or a Change of ControlOfficer Letter Retention Agreements and Recent Compensation Actions in 2015.
Restrictive Covenants. As a condition of purchasing our common stock and receiving the options, our named executive officers agreed to certain restrictive covenants, including confidentiality of information, an 18-month post-termination non-solicitation of employees covenant and a non-compete covenant for up to 18 months post-termination, which are contained in the related 2012 management stockholders agreements. The non-solicitation covenant is applicable for each month that the executive receives cash severance payments of no less than the sum total of (i) his then current monthly cash compensation at the time of such termination plus (ii) the amount of the Companys continued payment for health benefits to the executive. In the event of a breach of such restrictive covenants, the purchased stock and options will be treated as described above as if such executive was terminated for cause. On March 24, 2014, the option award agreements were amended such that any obligation by the executive not to compete with the Company after his termination of employment (for any reason) was removed, but preserving the confidentiality and non-solicitation provisions.
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2013 Options
The following describes the terms of the options granted to our named executive officers in fiscal year 2013.
Options Granted to Mr. Limbacher. Twenty-one percent of the shares subject to the options granted to Mr. Limbacher had an exercise price that equaled the grant date fair market value of the underlying shares of our common stock (the 2013 FMV Options), twenty-one percent of the shares subject to the option had an exercise price that was greater than the grant date fair market value of our common stock (the 2013 Base Price Options) and fifty-eight percent of the shares subject to the option had an exercise price equal to 1.5x the Base Price Options (the 2013 1.5x Base Price Options). Mr. Limbachers employment agreement was amended on April 1, 2014 to provide for (i) the forfeiture by Mr. Limbacher of 250,000 of the 2013 FMV Options, (ii) the forfeiture by Mr. Limbacher of 250,000 of the 2013 Base Price Options, and (iii) the repricing of 10,000,000 of his 2013 1.5x Base Price Options to an exercise price of $2.50 per share.
Originally, twenty percent of each of the 2013 FMV Options, the 2013 Base Price Options and 2013 1.5x Base Price Options were to vest on each of the first five anniversaries of April 18, 2013, subject to Mr. Limbachers continued employment with us on each vesting date. However, pursuant to the terms of the November 14, 2014 Officer Retention Letter Agreement with Mr. Limbacher, all of the options awarded to Mr. Limbacher as of November 14, 2014 will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. Additionally, pursuant to the Mr. Limbachers employment agreement, the options will become fully vested upon a change of control that occurs during his employment with us. In the event Mr. Limbacher resigns with good reason (as such term is defined in his employment agreement and as described below) subsequent to April 18, 2014 and following our initial public offering, affiliates of KKR, ITOCHU and certain other investors (the Sponsors) beneficially own less than 40% of our common stock (as measured against the number of shares the Sponsors held on April 18, 2013), then 100% of the shares subject to the option will vest immediately prior to such termination. Any options that remain unvested upon termination of employment and do not vest as described above will be forfeited.
Options Granted to Messrs. Cook, Fraley, Jones and Kidd. On March 24, 2014, we repriced outstanding stock options (including 2013 Options) held by each of our named executive officers, other than Mr. Limbacher, to reduce the exercise price per share to an exercise price of $2.50 per share. All new options granted to named executive officers in 2014 were granted at an exercise price of $2.50 per share.
Twenty percent of each the options vested on December 31, 2013 and December 31, 2014. The options will become fully vested as of September 1, 2015 (pursuant to the Officer Letter Retention Agreements), upon a change of control that occurs during employment with us, or, upon his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. Any options that remain unvested upon termination of employment and do not vest as described above will be forfeited.
Option Put Rights and Option Call Rights. The options granted in 2013 have substantially the same put and call rights that are applicable to the options granted in 2012 described above, other than with respect to the applicable trigger dates for call rights in the event the employee resigns without good reason. However, such options are not entitled to the liquidity program rights applicable to the options awarded in 2012 as described above.
Restrictive Covenants. As a condition of receiving the 2013 options, our named executive officers agreed to certain restrictive covenants, including confidentiality of information, an 18-month post termination non-solicitation of employees covenant, and a 12-month non-compete covenant (in the event of termination for cause or termination with good reason) or an 18-month non-compete covenant (in the event of termination without cause or termination with good reason), which are contained in the related 2013 management stockholders agreements. In the event of a breach of the non-solicitation covenant, the options will be treated as described above as if such executive was terminated for cause, and the Company will be entitled to cause any severance
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payments or benefits then provided to the executive to immediately cease and if the Company made any payments pursuant to exercise of its call rights, the executive has to repay to the Company any net after tax amounts received from the Company in respect of such vested options and stock. On March 24, 2014, the option award agreements were amended such that any obligation by the executive not to compete with the Company after his termination of employment (for any reason) was removed, but preserving the confidentiality and non-solicitation provisions.
2014 Options
Options Granted to Mr. Fraley. On March 24, 2014, Mr. Fraley was granted 800,000 options at an exercise price of $2.50 per share. 20% of these options vested on March 24, 2015. Pursuant to the terms of the Officer Retention Letter Agreement, the options will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. The options will also become fully vested upon a change of control that occurs during employment with us. Any options that remain unvested upon termination of employment and do not vest as described above will be forfeited.
Option Put Rights and Option Call Rights. The options granted in 2014 have substantially the same put and call rights that are applicable to the options granted in 2012 and 2013 described above, other than with respect to the applicable trigger dates for call rights in the event the employee resigns without good reason. However, such options are not entitled to the liquidity program rights applicable to the options awarded in 2012 as described above.
Terms of Restricted Stock Awards
Restricted Stock Granted to Mr. Limbacher. On April 18, 2013, we granted Mr. Limbacher 5,000,000 shares of restricted stock that initially vested with respect to one-third of the shares on each of the third, fourth and fifth anniversaries of April 18, 2013, subject to his continued employment with us on each vesting date. In the event he was terminated by us without cause or he resigned with good reason at least six months after April 18, 2013 but prior to April 18, 2014, then 20% of the shares would vest as of immediately prior to such termination. If such termination occurred on or after April 18, 2014 but prior to April 18, 2016, Mr. Limbacher would vest, as of the termination date, in the number of shares of restricted stock that would have vested if the vesting schedule was the first five anniversaries of April 18, 2013; provided, however, that if such termination occurs on or subsequent to April 18, 2014 and following our initial public offering, the Sponsors beneficially own less than 40% of our common stock (as measured against the number of shares such investors held on April 18, 2013), then 100% of the shares will vest on the date of such termination. The vesting terms to the 2013 restricted stock awards held by Mr. Limbacher were amended on March 24, 2014, such that the restricted stock awards would vest annually in four equal tranches beginning in April 1, 2015. However, pursuant to the terms of the Officer Retention Letter Agreement, all of Mr. Limbachers restricted stock will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the shares of restricted stock will also vest in full upon a change of control that occurs during Mr. Limbachers employment with us.
On March 24, 2014, we granted Mr. Limbacher 2,500,000 shares of restricted stock, which were originally set to vest with respect to one-fifth of the shares on each of the first, second, third, fourth, and fifth anniversaries of April 1, 2014, subject to Mr. Limbachers continued employment with us on each vesting date. In the event he was terminated by us without cause or he resigned for good reason at least six months after March 24, 2014 but prior to March 24, 2015, then 20% of the shares would vest as of immediately prior to such termination. If such termination occurred on or after March 24, 2015, but prior to March 24, 2018, Mr. Limbacher would vest, as of the termination date, in the number of shares of restricted stock that would have vested if the vesting schedule was the first five anniversaries of March 24, 2014; provided, however, that if such termination occurred on or subsequent to April 1, 2015 and following an initial public offering in which the Sponsors beneficially own less than 40% of our common stock (as measured against the number of shares the Sponsors held on March 24,
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2014), then 100% of the shares will vest on the date of such termination. However, pursuant to the terms of his Officer Retention Letter Agreement, all of Mr. Limbachers restricted stock will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the shares of restricted stock will also vest in full upon a change of control that occurs during Mr. Limbachers employment with us. Any shares of that remain unvested upon termination of employment and do not vest as described above will be forfeited.
Restricted Stock Granted to Messrs. Cook, Fraley, Jones and Kidd. We granted 400,000 shares of restricted stock to Mr. Cook on May 20, 2013, and we granted 400,000 shares of restricted stock to Mr. Fraley on July 29, 2013 and 400,000 shares of restricted stock to Mr. Jones on August 5, 2013. The restricted stock granted to Messrs. Fraley and Jones initially was scheduled to vest with respect to one-third of the shares on each of September 4, 2016, September 4, 2017 and September 4, 2018, and the restricted stock granted to Mr. Cook was scheduled to vest with respect to one-third of the shares on each of January 1, 2016, January 1, 2017 and January 1, 2018, subject to the executives continued employment with us on each applicable vesting date. In the event the executive was terminated by us without cause, the number of shares that would vest on such termination date is determined as if the restricted shares were scheduled to vest with respect to 20% of the shares on each of the first five anniversaries of the applicable vesting commencement date. The vesting terms to the 2013 restricted stock awards held by the executives were amended on March 24, 2014, such that (i) all such restricted stock awards (other than those held by Mr. Limbacher) will immediately vest in the event that the employees employment is terminated by us without cause or the employee resigns for good reason, in each case, within two years of a change in control, and (ii) the 2013 restricted stock awards would vest annually in four equal tranches beginning in April 2015. However, pursuant to the November 14, 2014 Officer Retention Letter Agreements, all of the executives restricted stock will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. Any shares that remain unvested upon termination of employment and do not vest as described above will be forfeited.
We granted 1,300,000, 1,450,000, 600,000 and 1,000,000 shares of restricted stock to each of Messrs. Cook, Fraley, Jones and Kidd, respectively, on March 24, 2014. The restricted stock granted to these named executive officers will vest 20% on each of the first, second, third, fourth, and fifth anniversaries of April 1, 2014, subject to the named executive officers continued employment with us on each vesting date. In the event the named executive officers employment terminates due to death or disability, then 20% of the shares that would otherwise vest on the next vesting date will vest upon the date of such termination. In addition, in the event that the named executive officers employment is terminated by us other than for cause or the named executive officer resigns for good reason, in each case, within two years of a change of control, 100% of the shares will vest. However, pursuant to the November 14, 2014 Officer Retention Letter Agreements, all of the executives restricted stock will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. Any shares that remain unvested upon termination of employment and do not vest as described above will be forfeited.
Put Rights. The restricted stock granted in 2013 and 2014 is subject to a put right if the executives employment terminates due to death or disability. In that event, for a specified period following the termination date, the executive (or his estate, as applicable) has the right to cause us to purchase on one occasion all stock at a price equal to fair market value. Additionally, pursuant to the Officer Retention Letter Agreements, if the executive remains employed with the company through September 1, 2015 or is terminated by the company for any reason other than cause prior to September 1, 2015, the restricted stock was to be subject to a temporary put right beginning September 2, 2015. The put rights under the Officer Retention Letter Agreements were terminated pursuant to the Release Letter Agreements to be effective March 31, 2015. For further discussion see Potential Payments Upon a Termination or a Change of Control Officer Retention Letter Agreements and Recent Compensation Actions in 2015.
Call Rights. The stock is also subject to certain call rights in favor of us. If the executives employment is terminated by us without cause, the executive resigns for good reason or the executive resigns without good
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reason on or after a specified date, we have the right to purchase from the executive all or any portion of the stock then held by the executive at a price equal to fair market value. If the executives employment is terminated by us for cause or the executive resigns without good reason prior to such specified date, the repurchase price will be the lesser of the price paid for the shares (which would be zero) or fair market value. Additionally, pursuant to the Officer Retention Letter Agreements, if the executive remains employed with the company through September 1, 2015 or is terminated by the company for any reason other than cause prior to September 1, 2015, the restricted stock was to be subject to a temporary call right beginning September 2, 2015. The call rights under the Officer Retention Letter Agreements were terminated pursuant to the Release Letter Agreements to be effective March 31, 2015. For further discussion see Potential Payments Upon a Termination or a Change of Control Officer Retention Letter Agreements and Recent Compensation Actions in 2015.
Outstanding Equity Awards at 2014 Fiscal Year End
The following table provides information regarding outstanding awards made to our named executive officers as of December 31, 2014.
Option Awards(1) | Stock Awards | |||||||||||||||||||||||||||||||
Name |
Option Grant Date |
Number of Securities Underlying Unexercised Options (#) Exercisable |
Number of Securities Underlying Unexercised Options (#) Unexercisable |
Option Exercise Price ($) |
Option Expiration Date |
Stock Award Grant Date |
Number of Shares or Units of Stock That Have Not Vested (#) |
Market Value of Shares or Units of Stock That Have Not Vested ($) |
||||||||||||||||||||||||
Randy L. Limbacher |
4/18/13 | 1,200,000 | 4,800,000 | (2) | $ | 5.00 | 4/18/2023 | 3/24/14 | 2,500,000 | (6) | 625,000 | |||||||||||||||||||||
4/18/13 | 2,000,000 | 8,000,000 | (2) | $ | 2.50 | 4/18/2023 | 4/18/13 | 5,000,000 | (5) | 1,250,000 | ||||||||||||||||||||||
4/18/13 | 1,200,000 | 4,800,000 | (2) | $ | 4.00 | 4/18/2023 | ||||||||||||||||||||||||||
4/18/13 | 1,500,000 | 6,000,000 | (2) | $ | 7.50 | 4/18/2023 | ||||||||||||||||||||||||||
Philip W. Cook |
5/20/13 | 480,000 | 720,000 | $ | 2.50 | 5/20/2023 | 3/24/14 | 1,300,000 | (8) | 325,000 | ||||||||||||||||||||||
4/16/12 | 900,000 | 300,000 | (3) | $ | 2.50 | 4/16/2022 | 5/20/13 | 400,000 | (7) | 100,000 | ||||||||||||||||||||||
Richard E. Fraley |
3/24/14 | | 800,000 | (4) | $ | 2.50 | 3/24/2024 | 3/24/14 | 1,450,000 | (8) | 362,500 | |||||||||||||||||||||
7/29/13 | 480,000 | 720,000 | $ | 2.50 | 7/29/2023 | 7/29/13 | 400,000 | (7) | 100,000 | |||||||||||||||||||||||
7/29/13 | 480,000 | 720,000 | $ | 2.50 | 7/29/2023 | |||||||||||||||||||||||||||
Louis D. Jones |
8/5/13 | 500,000 | 750,000 | $ | 2.50 | 8/5/2023 | 3/24/14 | 600,000 | (8) | 150,000 | ||||||||||||||||||||||
8/5/13 | 300,000 | 450,000 | $ | 2.50 | 8/5/2023 | 8/5/13 | 400,000 | (7) | 100,000 | |||||||||||||||||||||||
Andrew C. Kidd |
9/9/13 | 480,000 | 720,000 | $ | 2.50 | 9/9/2023 | 3/24/14 | 1,000,000 | (8) | 250,000 | ||||||||||||||||||||||
9/9/13 | 240,000 | 360,000 | $ | 2.50 | 9/9/2023 |
(1) | Unless otherwise noted, options vested 20% on December 31, 2013 and 20% on December 31, 2014, and will fully vest on September 1, 2015 or the executives termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All options will also vest upon a change of control that occurs during employment with us. |
(2) | These options vested 20% on April 18, 2014, will vest another 20% on April 18, 2015, and will fully vest on September 1, 2015 or the executives termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All options will also vest upon a change in control that occurs during the executives employment with us. |
(3) | These options vested 25% on each of December 21, 2012, December 21, 2013 and December 21, 2014, and will fully vest on September 1, 2015 or the executives termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All options will also vest upon a change of control that occurs during employment with us. |
(4) | These options vested 20% on March 24, 2015, and will fully vest on September 1, 2015 or the executives termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All options will also vest upon a change of control that occurs during employment with us. |
(5) | The stock will vest 25% on April 1, 2015 and will be fully vest on September 1, 2015 or the executives termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the stock will also vest upon a change of control that occurs during employment with us. |
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(6) | The stock will vest 20% on April 1, 2015 and will fully vest on September 1, 2015 or the executives termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the stock will also vest upon a change of control that occurs during employment with us. |
(7) | The stock will vest 25% on April 1, 2015 and will be fully vest on September 1, 2015 or the executives termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the stock will also vest if, within two years following a change in control, the executive resigns for good reason. |
(8) | The stock will vest 20% on April 1, 2015 and will be fully vest on September 1, 2015 or the executives termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015.All of the stock will also vest if, within two years following a change in control, the executive resigns for good reason. |
Option Exercises and Stock Vested in Fiscal Year 2014
None of our named executive officers had any stock option exercises or stock vested during 2014.
Pension Benefits
We do not currently provide pension benefits to our employees.
Nonqualified Deferred Compensation
We do not currently provide nonqualified deferred compensation benefits to our employees.
Potential Payments Upon a Termination or a Change of Control
Change in Control Severance Plan for Officers
Under the terms of the Samson Resources Corporation Change in Control Severance Plan for Officers, effective as of January 1, 2014, if (i) the participants (which includes all of the named executive officers other than Mr. Limbacher) employment is terminated by the Company without cause, or (ii) the participant resigns for good reason during the period beginning on the date upon which the definitive agreement that results in the Change in Control (as defined in the Change in Control Severance Plan) takes effect until the date that is two years following the date of the Change in Control, such participant is entitled to receive the following payments, subject to the participants execution and non-revocation of a valid release:
| A pro-rated portion of the participants target bonus for the year of termination, determined by multiplying such target bonus by a fraction, the numerator of which equals the number of days in the relevant fiscal year elapsed through the termination date and the denominator of which equals 365; |
| A cash payment (the Cash Payment) equal to the sum of two times the participants (i) annual base salary in effect immediately prior to the date of termination of employment, or, if higher, in effect immediately prior to the first occurrence of an event constituting good reason, plus (ii) three-year average annual bonus received for the three full completed fiscal years preceding (or a lesser number of full years for participants who have not been employed for that long) the change in control; and |
| Provided that the participant timely elects of continued COBRA coverage, the Companys reimbursement of COBRA premiums for medical, dental, and vision coverage for the participant and any of his eligible dependents covered as of the participants date of termination, for the period of time beginning on his date of termination and continuing for up to 24 months thereafter. |
The Cash Payment will be paid in 12 equal monthly installments, with the first installment being paid on the 60th day following the termination date. The Participant will receive the Cash Payment in lieu of any other
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severance benefit to which the Participant would be otherwise entitled under any other agreements or arrangements with the Company, excluding those payments and benefits required by law.
The participants eligibility to receive these payments is contingent upon him not violating a one-year covenant not to solicit Company employees, and indefinite non-disparagement and confidentiality covenants.
The Change in Control Severance Plan also provides that, in the event that any payment received or to be received by a participant in connection with either a change in control or any termination of a participants employment would be subject (in whole or in part) to the excise tax imposed under Section 4999 of the Internal Revenue Code, such payment will be reduced to the extent necessary to avoid any such applicable tax, but only if such reduction would result in greater or equal net after-tax receipt of payments and benefits to the participant.
On November 14, 2014, the Change in Control Severance Plan was amended such that effective September 1, 2015 Change of Control shall mean:
(i) the sale of all or substantially all of the assets (i.e., at least 80%) (in one transaction or a series of related transactions) of Samson Resources Corporation (SRC), a corporation controlled by affiliates of Kohlberg Kravis Roberts & Co. L.P., Itochu Corporation, Natural Gas Partners L.P. and Crestview Partners II GP, L.P. (together, the Sponsors) or Samson Investment Company (SIC), as applicable, which, based on transactions consummated as of September 1, 2015, are held by SRC, SIC or any of their respective Subsidiaries or any entity that is controlled by SRC or SIC and are not as of such date contemplated for sale, to any Person (or group of Persons acting in concert), other than to the Sponsors or their affiliates; or (ii) a merger, recapitalization or other sale (in one transaction or a series of related transactions) by SRC, the Sponsors or any of their respective affiliates (which includes, for the avoidance of doubt, SIC), to a Person (or group of Persons acting in concert) of equity interests or voting power that results in any Person (or group of Persons acting in concert) (other than the Sponsors or their affiliates) owning more than 50% of the equity interests or voting power of SRC or SIC, as applicable (or any resulting company after a merger). For purposes of determining if an asset is sold under clause (i) above, the sale of primary equity securities in a direct or indirect subsidiary of SRC or SIC to the public or a third party shall not be deemed to be an asset sale; provided, however, that a sale of secondary equity securities in any such subsidiary shall be considered an asset sale to the extent of such sale. For the avoidance of doubt, none of an initial public offering, stock dividend, stock split or any other similar corporate event shall alone constitute a Change of Control.
Pursuant to its terms, the Change in Control Severance Plan may be amended or terminated by our Compensation Committee at any time, provided that any amendment or termination that materially reduces benefits to, or eliminates, participants, will not be effective until one year after we provide written notice to participants.
Mr. Limbachers Employment Agreement
Under the terms of the employment agreement Mr. Limbacher entered into with us, effective as of April 18, 2013, as amended in August 2014, if Mr. Limbachers employment is terminated by us without cause, he resigns for good reason after September 1, 2015, in connection with a change of control or upon non-renewal of the agreement by the Company, he will be entitled to receive:
| 200% of his annual base salary as of the termination date; |
| 200% of the greater of (i) the annual bonus earned in respect of the immediately preceding fiscal year (other than the Special Bonus) and (ii) his target bonus for the current fiscal year; and |
| a pro-rated portion of his target bonus for the current fiscal year, determined by multiplying such target bonus by a fraction, the numerator of which equals the number of days in the relevant fiscal year elapsed through his termination date and the denominator of which equals 365. |
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Such cash severance payments would be payable in substantially equal monthly installments over the twenty-four (24) month period beginning on the termination date (the severance period); provided that if such termination occurs upon or within two years following a change of control, such amount would be payable as a lump sum on the 60th day following his termination date. During the severance period, Mr. Limbacher will also receive reimbursement for the difference between the monthly premium paid by him for continuation coverage under COBRA and the monthly premium charged to our active senior executives for health insurance coverage, subject to earlier cut off if he becomes eligible for health insurance coverage under a subsequent employers plan.
Restrictive Covenants. Under the terms of his employment agreement, Mr. Limbacher has agreed not to disclose our confidential information at any time during his employment with us or thereafter, and, for the period during which he is employed with us and for the twenty-four month period following his termination date, he has also agreed not to solicit our employees or anyone engaged to perform services for us. Our obligations to provide cash severance payments under the termination scenarios described above are subject to Mr. Limbachers compliance with the confidentiality and non-solicitation covenants unless his termination occurs after a change in control. In addition, if he competes with our business during the severance period, our obligation to make such cash severance payments would end upon the later of 12 months after his termination date and the date on which he first engaged in such restricted activities unless his termination occurs after a change in control.
For purposes of Mr. Limbachers employment agreement, cause generally means Mr. Limbachers (i) commission of any serious crime involving fraud, dishonesty or a breach of trust as to us, (ii) material violation of any our confidential and proprietary information policies or applicable code of conduct policy, (iii) conviction, guilty plea or no contest plea regarding any felony or any crime involving moral turpitude, or (iv) intentional and repeated failure to perform his duties in any material respect (other than due to physical or mental illness or disability) or his gross negligence or intentional misconduct in the performance of his duties. Good reason means a material diminution in Mr. Limbachers base salary or target bonus opportunity, a relocation of his current place of employment to a location that is more than 25 miles away, or a material diminution in Mr. Limbachers duties and responsibilities with us. A change of control has the meaning ascribed to such term under our 2011 Plan and is described above under Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 TableTerms of Option Awards.
Mr. Cooks Special Agreement
Under the terms of the special agreement Mr. Cook entered into with us, effective April 16, 2012, as amended in August 2014, if Mr. Cook is terminated without cause or for good reason within one year following our change of control, he will be entitled to a cash lump sum payment equal to 200% of his annual base salary as of the termination date plus an amount equal to the last annual bonus Mr. Cook received prior to the termination date (other than the Special Bonus). Under the agreement, good reason includes and of the following occurring after September 1, 2015: (i) a diminution in Mr. Cooks annual base salary or opportunity to earn an annual bonus; (ii) relocation of Mr. Cooks primary place of employment to a location more than 50 miles from his primary place of employment as of immediately prior to such relocation; (iii) a material breach by us of any of our obligations under this agreement; or (iv) the assignment of duties and responsibilities on a continuing basis to Mr. Cook that are materially inconsistent with his position or title prior to such assignment. A change of control has the meaning ascribed to such term under our 2011 Plan and is described above under Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 TableTerms of Option Awards. As consideration for any severance under this agreement, Mr. Cook must execute, deliver and not revoke a release of claims in favor of us within 60 days following his termination and continue to comply with our confidential information and material policy and our business and ethics code of conduct policy.
Special Agreements with Messrs. Fraley and Jones
Under the terms of the special agreement each of Mr. Fraley and Mr. Jones entered into with us, effective August 1, 2013 and August 5, 2013, respectively, and each as amended in August 2014, if each such executive is
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terminated (i) without cause within two years from the date of the agreement or (ii) without cause or for good reason within one year following a change of control, each will be entitled to a cash lump sum payment equal to 150% of his annual cash compensation as of the termination date, which includes both annual base salary and annual bonus.
Under the special agreement, good reason includes a diminution in Mr. Fraleys or Mr. Jones annual base salary or opportunity to earn an annual bonus; relocation of Mr. Fraleys or Mr. Jones primary place of employment to a location more than 50 miles from his primary place of employment as of immediately prior to such relocation; a material breach by us of any of our obligations under this agreement; or the assignment of duties and responsibilities on a continuing basis to Mr. Fraley or Mr. Jones that are materially inconsistent with his position or title prior to such assignment. A change of control has the meaning ascribed to such term under our 2011 Plan and is described above under Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 TableTerms of Option Awards. As consideration for any severance under this agreement, each executive must execute, deliver and not revoke a release of claims in favor of us within 60 days following his termination and continue to comply with our confidential information and material policy and our business and ethics code of conduct policy.
Additionally, in 2014, Mr. Jones special agreement was amended such that in the event of retirement or permanent disability, he has the ability to retain the then vested portion of any restricted stock or stock options (which may be exercised at any time during the term of such options). Mr. Jones employment with the Company was terminated effective March 31, 2015.
Officer Retention Letter Agreements
In order to further incentivize the retention of our officers, including each of our named executive officers, on November 14, 2014, the Company entered into a retention letter agreement with each named executive officer, which provides for, among other things:
| If such named executive officer remains employed by the Company through September 1, 2015 (the Retention Date) and satisfies the other terms and conditions of the letter agreement, a retention award (the Retention Award) having a value equal to two times the sum of such named executive officers (1) annual base salary and (2) target bonus for 2015 (the Retention Award Amount); |
| If such executive officer continues employment with the Company after the Retention Date (Remaining Officer) he will receive his respective Retention Award in the form of a grant of shares of fully vested stock having a value equal to the Retention Award Amount, which stock will not be subject to forfeiture or repurchase for less than fair market value. Officers that voluntarily terminate their employment as of the Retention Date (Departing Officer) will receive their respective Retention Award in the form of cash pursuant to the terms of the Officer Voluntary Severance Plan as described further below. |
Both Remaining Officers and Departing Officers receive the accelerated vesting of 100% of all shares of restricted stock and stock options held by such named executive officer as of November 14, 2014, with vesting occurring as of the Retention Date; and
| Special put and call rights with respect to vested shares of restricted stock and stock options that may be exercised within a 30-day period following the Retention Date (with respect to Remaining Officers) or within a 90-day period following the Retention Date (with respect to Departing Officers), which will entitle such officer or the Company, as applicable, to cause the repurchase of such shares and options by the Company in an amount equal to their fair market value on the repurchase date (less the exercise price, in the case of options). At the end of such exercise period, the put and call rights provided for under the retention letter agreements will terminate, and any put, call or other similar rights relating to named executive officers equity awards will be governed by the terms and conditions of the 2011 Plan and the related stockholders agreements. |
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The retention letter agreements also provide that if an named executive officers employment is terminated by the Company other than for cause prior to the Retention Date, such named executive officer will be entitled to, in addition to certain accrued rights, a pro-rated target bonus for the year of termination, (1) subject to executing a release of claims, a cash severance award, paid in 13 substantially equal semi-monthly installments but in no event later than March 15 of the calendar year immediately following that in which the termination date occurs, and other payments identical to those provided under the Officer Voluntary Severance Plan (other than for Mr. Limbacher) and (2) accelerated equity vesting and special temporary put and call rights that are substantially similar to those described above for Departing Officers. As consideration for any severance under this agreement, each named executive officer must execute, deliver and not revoke a release of claims in favor of us and continue to comply with our confidential information and material policy and our business and ethics code of conduct policy.
In March 2015, the Company entered Release Agreements with the officers which superseded the Officer Retention Letter Agreements in all respects, including the Officer Voluntary Severance Plan, with the exception of the accelerated vesting of equity awards, which will continue to be fully vested as of September 1, 2015, and the COBRA reimbursement payments for eligible officers. For further discussion, see Recent Compensation Actions in 2015.
Officer Voluntary Severance Plan
In connection with the approval of the retention letter agreements, the Compensation Committee adopted the Officer Voluntary Severance Plan, effective as of November 14, 2014. The Officer Voluntary Severance Plan is administered by the Compensation Committee.
Remaining Officers that provide timely notice of their decision to terminate their employment as of the Retention Date will be entitled to certain severance payments under the Officer Voluntary Severance Plan, including, among other things:
| the payment of a pro-rated portion of such officers target bonus for 2015 and certain accrued obligations, to be paid in a lump sum within 60 days of termination; |
| the payment of the Retention Award described above, generally to be paid in cash in 13 substantially equal semi-monthly installments; and |
| if elected, monthly payments equal to the COBRA premiums for medical, dental and vision coverage to be paid for up to 24 months. |
A qualifying officers receipt of these payments is contingent upon such officer signing, and not revoking, a release of claims against the Company and its affiliates and agreeing to certain customary confidentiality, non-solicitation and non-disparagement restrictions. Any officer receiving severance payments and benefits under the retention letter agreements or the Officer Voluntary Severance Plan will generally not be entitled to receive any other payments or benefits in connection with such officers termination under any other plan, agreement or arrangement.
In March 2015, the Company entered Release Agreements with the officers which superseded the Officer Retention Letter Agreements in all respects with the exception of the accelerated vesting of equity awards, which will continue to be fully vested as of September 1, 2015, and the COBRA reimbursement payments for eligible officers. For further discussion, see Recent 2015 Compensation Actions.
Option Award Agreements
Under the terms of the option award agreements, the options granted to our named executive officers will become fully vested upon a change in control that occurs during the executive officers employment with us. A change of control has the meaning ascribed to such term under our 2011 Plan and is described above under
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Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 TableTerms of Option Awards.
In the case of 2012 options, the Option Award Agreements provide that twenty-five percent (25%) of the shares subject to the option that would otherwise vest on the next vesting date will vest upon the executive officers termination of employment without cause or with good reason or due to death or disability.
In the case of 2013 options (other than Mr. Limbachers options), the Option Award Agreements provide that in the event the executive dies or becomes disabled, then twenty percent (20%) of the shares subject to the option that would otherwise vest on the next vesting date will vest upon the date of such termination.
In the case of Mr. Limbachers 2013 options, his employment agreement provides that in the event he is terminated by us without cause or he resigns with good reason (as each such term is defined in his employment agreement and as described above) at least six months after April 18, 2013 but prior to April 18, 2014, then the portion of the options that would have vested on April 18, 2014 will vest and become exercisable as of immediately prior to his termination. If such termination occurs on or subsequent to April 18, 2014 and following our initial public offering, the Sponsors beneficially own less than 40% of our common stock (as measured against the number of shares the Sponsors held on April 18, 2013), then 100% of the shares subject to the option will vest immediately prior to such termination. If Mr. Limbacher dies or becomes disabled, then twenty percent of the shares subject to the option that would otherwise vest on the next vesting date will vest upon the date of such termination.
However, pursuant to November 14, 2014 Officer Retention Letter Agreements, if any of the named executives is terminated by the Company for any reason except for Cause prior to September 1, 2015, or if the executive remains employed through September 1, 2015, all unvested options held by the executive as of November 14, 2014 shall be fully vested as of September 1, 2015.
Any options that remain unvested upon termination of employment and do not vest as described above will be forfeited.
Restricted Stock Award Agreements
Under the terms of Mr. Limbachers restricted stock award agreement, in the event he is terminated by us without cause or he resigns with good reason at least six months after April 18, 2013 but prior to April 18, 2014, then 20% of the shares would vest as of immediately prior to such termination. If such termination occurs on or after April 18, 2014 but prior to April 18, 2016, Mr. Limbacher will vest, as of the termination date, in the number of shares of restricted stock that would have vested if the vesting schedule was the first five anniversaries of April 18, 2013; provided, however, that if such termination occurs on or subsequent to April 18, 2014 and following our initial public offering, the Sponsors beneficially own less than 40% of our common stock (as measured against the number of shares the Sponsors held on April 18, 2013), then 100% of the shares will vest on the date of such termination. All of Mr. Limbachers shares of restricted stock will vest in full upon a change of control that occurs during employment with us.
Under the terms of the other named executive officers restricted stock award agreements, in the event the executive is terminated by us without cause, the number of shares that will vest on such termination date is determined as if the restricted shares were scheduled to vest with respect to 20% of the shares on each of the first five anniversaries of the applicable vesting commencement date. Any shares that remain unvested upon termination of employment and do not vest as described above will be forfeited.
On March 24, 2014, the vesting terms to the restricted stock awards held by employees (other than Mr. Limbacher), including our named executive officers, were amended to provide that (i) all restricted stock awards will immediately vest upon a change-in-control and a qualifying termination of employment and (ii) the 2013 restricted stock awards will now vest annually in four equal tranches beginning in 2015. The Compensation
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Committee also approved an agreement with Mr. Jones permitting him, in the event of retirement or permanent disability, to retain the then vested portion of any restricted stock or stock options (which may be exercised at any time during the term of such options).
However, pursuant to November 14, 2014 Officer Retention Letter Agreements, if any of the named executives is terminated by the Company for any reason except for Cause prior to September 1, 2015, or if the executive remains employed through September 1, 2015, all unvested restricted stock held by the executive as of November 14, 2014 shall be fully vested as of September 1, 2015.
The following table describes the potential payments and benefits under our compensation and benefit plans and contractual agreements to which our named executive officers would have been entitled assuming a Change of Control and/or their employment had been terminated on December 31, 2014.
Change of Control(3) | Termination by Company without Cause (without a Change of Control)(4) |
Termination by Company without Cause or for by Executive for Good Reason in Connection with a Change of Control(4)(5) |
Death or Disability | |||||||||||||
Randy L. Limbacher: |
||||||||||||||||
Cash Severance (including pro-rata bonus) |
$ | | $ | 4,150,000 | (6) | $ | | $ | | |||||||
Equity Acceleration(1) |
$ | 1,875,000 | $ | 1,875,000 | $ | | $ | 1,875,000 | ||||||||
Continuing Medical(2) |
$ | | $ | 21,358 | $ | | $ | | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 1,875,000 | $ | 6,046,358 | $ | | $ | 1,875,000 | ||||||||
Philip W. Cook: |
||||||||||||||||
Cash severance |
$ | | $ | 2,750,000 | $ | 2,800,000 | $ | 2,750,000 | ||||||||
Equity Acceleration(1) |
$ | | $ | 425,000 | $ | 425,000 | $ | 425,000 | ||||||||
Continuing Medical |
$ | | $ | 39,557 | $ | 39,557 | $ | 39,557 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | | $ | 3,214,557 | $ | 3,264,557 | $ | 3,214,557 | ||||||||
Richard E. Fraley: |
||||||||||||||||
Cash severance |
$ | | $ | 2,750,000 | $ | 2,750,000 | $ | 2,750,000 | ||||||||
Equity Acceleration(1) |
$ | | $ | 462,500 | $ | 462,500 | $ | 462,500 | ||||||||
Continuing Medical(2) |
$ | | $ | 39,557 | $ | 39,557 | $ | 39,557 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | | $ | 3,252,057 | $ | 3,252,057 | $ | 3,252,057 | ||||||||
Louis D. Jones: |
||||||||||||||||
Cash severance |
$ | | $ | 2,475,000 | $ | 2,475,000 | $ | 2,475,000 | ||||||||
Equity Acceleration(1) |
$ | | $ | 250,000 | $ | 250,000 | $ | 250,000 | ||||||||
Continuing Medical |
$ | | $ | 3,250 | $ | 3,250 | $ | 3,250 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | | $ | 2,728,250 | $ | 2,728,250 | $ | 2,728,250 | ||||||||
Andrew C. Kidd: |
||||||||||||||||
Cash severance |
$ | | $ | 2,075,000 | $ | 2,075,000 | $ | 2,075,000 | ||||||||
Equity Acceleration(1) |
$ | | $ | 250,000 | $ | 250,000 | $ | 250,000 | ||||||||
Continuing Medical |
$ | | $ | 39,557 | $ | 39,557 | $ | 39,557 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | | $ | 2,364,557 | $ | 2,364,557 | $ | 2,364,557 |
(1) | Reflects the value as of the last business day of 2014 of the additional benefit from the acceleration of vesting of restricted stock that would have occurred as a result of termination under the circumstances specified. This value has been determined with respect to each named executive officer by multiplying $.25 per share by the number of shares of restricted stock that would vest upon termination or Change in |
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Control. See Restricted Stock Award Agreements above for vesting terms of restricted stock. No values have been added for the acceleration of vesting of options under the specified termination scenarios in the table above because as of December 31, 2014, the exercise price of the options exceeded the fair market value of our common stock based on our valuation determination. See Option Award Agreements above for vesting terms of options. |
(2) | Represents the maximum value for continuation of coverage under COBRA for the full duration of the severance period that the executive could receive under the terms of the Change in Control Severance Plan, his Officer Retention Agreement, or, in the case of Mr. Limbacher, his employment agreement. |
(3) | This column represents values incurred as a result of a Change of Control without a termination of employment. |
(4) | Pursuant to the Samson Resources Corporation Change in Control Severance Plan for Officers, an executive is eligible for severance if terminated by the Company without Cause or if he voluntarily resigns for Good Reason from the date on which an agreement is signed that results in a Change in Control and for two years following the Change in Control. |
(5) | Effective November 14, 2014, Mr. Limbacher waived the right to receive severance under his employment agreement in the event he voluntarily terminated employment without Good Reason prior to September 1, 2015. Similarly, Messers. Cook, Fraley and Jones waived the right to receive severance under their individual special agreements in the event of voluntary termination of employment without Good Reason prior to September 1, 2015. |
(6) | In the event Mr. Limbacher was terminated on or within two years of a change of control, his cash severance would be payable in a lump sum on the 60th day following termination. |
Director Compensation
Under the terms of the stockholders agreement we entered into with Samson Aggregator and other stockholders named therein, we pay our non-employee directors $60,000 per annum on a quarterly basis for their services on our Board of Directors. We also reimburse our non-employee directors for reasonable out of pocket expenses incurred by the directors in connection with their attendance at Board of Directors or other committee meetings. The annual director fee may be paid to the director directly or the person that designated or nominated the director, as specified by the director.
The following table provides summary information concerning the compensation of our non-employee directors for the fiscal year ended December 31, 2014.
Name |
Fees Earned or Paid in Cash ($) |
Stock Awards ($) |
Option Awards ($) |
All Other Compensation ($) |
Total ($) |
|||||||||||||||
Robert V. Delaney, Jr. |
$ | 60,000 | | | | $ | 60,000 | |||||||||||||
Claire S. Farley |
$ | 60,000 | | | | $ | 60,000 | |||||||||||||
Brandon A. Freiman |
$ | 60,000 | | | | $ | 60,000 | |||||||||||||
Scott Gieselman(1) |
$ | 60,000 | | | | $ | 60,000 | |||||||||||||
Toshiyuki Mori |
$ | 60,000 | | | | $ | 60,000 | |||||||||||||
David C. Rockecharlie |
$ | 60,000 | | | | $ | 60,000 | |||||||||||||
Jonathan D. Smidt |
$ | 60,000 | | | | $ | 60,000 | |||||||||||||
Ashwini Upadhyaya(2) |
$ | 45,000 | | | | $ | 45,000 | |||||||||||||
Akihiro Watanabe |
$ | 60,000 | | | | $ | 60,000 |
1) | Resigned effective January 12, 2015. |
2) | Resigned effective July 1, 2014. |
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Compensation Committee Report
The Compensation Committee has reviewed and discussed the foregoing Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussion, the Compensation Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this report.
Compensation Committee Members:
Jonathan D. Smidt
Robert V. Delaney, Jr.
Claire S. Farley
Toshiyuki Mori
Compensation Committee Interlocks and Insider Participation
During the fiscal year ended 2014, our former director, Mr. Gieselman, and each of Ms. Farley and Messrs. Smidt, Delaney and Mori served at various times as members of the Compensation Committee of Samson Resources Corporation. As discussed under Part III, Item 13Certain Relationships and Related Transactions, and Director Independence, each of these individuals was or is a director designee of one of our Principal Stockholders pursuant to the terms of the stockholders agreement among us and the Principal Stockholders.
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ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The following table sets forth, as of December 31, 2014, the beneficial ownership of common stock of Samson Resources Corporation by each person known by us to beneficially own more than 5% of the voting securities of Samson Resources Corporation, each director, each named executive officer and all directors and executive officers as a group. Unless otherwise indicated in the footnotes to this table, we believe that each person has sole voting and investment power of the shares.
Name |
Number of Shares Beneficially Owned(1)(2) |
Percent Class | ||||||
Samson Aggregator L.P.(3) |
621,000,000 | 72.5 | % | |||||
JD Rockies Resources Limited(4) |
208,000,000 | 24.3 | % | |||||
Randy L. Limbacher |
13,400,000 | 1.6 | % | |||||
Philip W. Cook |
3,080,000 | * | ||||||
Richard E. Fraley |
2,810,000 | * | ||||||
Louis D. Jones |
1,800,000 | * | ||||||
Andrew C. Kidd |
1,720,000 | * | ||||||
Robert V. Delaney, Jr.(3)(5) |
| | ||||||
Claire S. Farley(3)(6) |
| | ||||||
Brandon A. Freiman(3)(6) |
| | ||||||
Toshiyuki Mori(4)(7) |
| | ||||||
David C. Rockecharlie(3)(6) |
| | ||||||
Jonathan D. Smidt(3)(6) |
| | ||||||
Akihiro Watanabe(4)(7) |
| | ||||||
All directors and executive officers as a group (19 persons) |
27,780,000 | 3.2 | % |
* | Less than one percent. |
(1) | Shares beneficially owned include unvested shares of restricted stock held by our executive officers, including with respect to our named executive officers as follows: Mr. Limbacher7,500,000 shares; Mr. Cook1,700,000 shares; Mr. Fraley1,850,000 shares; Mr. Jones1,000,000 shares; and Mr. Kidd1,000,000 shares. |
(2) | Shares beneficially owned include the number of shares subject to stock options held by our executive officers that are exercisable or will become exercisable within 60 days of December 31, 2014, including with respect to our named executive officers as follows: Mr. Limbacher5,900,000 options; Mr. Cook1,380,000 options; Mr. Fraley960,000 options; Mr. Jones800,000; and Mr. Kidd720,000 options. |
(3) | Samson Aggregator L.P. is a limited partnership in which investment funds associated with Kohlberg Kravis Roberts & Co. L.P., including KKR Samson Investors L.P., and other co-investors, including investment funds affiliated with Crestview Partners II GP, L.P. and Natural Gas Partners IX, L.P., indirectly own the limited partner interests and membership interests of Samson Aggregator GP LLC, the general partner of Samson Aggregator L.P. KKR Samson Investors GP LLC is the general partner of KKR Samson Investors L.P. KKR Samson Investors L.P. is a limited partnership in which Samson Co-Invest I LP, Samson Co-Invest II LP, Samson Co-Invest III LP, KKR 2006 Fund (Samson) L.P., 8 North America Investor L.P., KKR Financial Holdings III, LLC, KKR Fund Holdings L.P., KKR Management Holdings L.P., KKR Partners III, L.P., KKR SA Investors Co-Invest Fund L.P., Lion Rock Energy Investor L.P. and OPERF Co-Investment LLC own the limited partner interests. Samson Co-Invest GP LLC is the general partner of each of Samson Co-Invest I LP, Samson Co-Invest II LP and Samson Co-Invest III LP. KKR Fund Holdings L.P. is the sole member of Samson Co-Invest GP LLC. KKR 2006 Fund (Samson) L.P. is the sole member of KKR Samson Investors GP LLC. KKR Associates 2006 L.P. is the general partner of KKR 2006 Fund (Samson) L.P. KKR 2006 GP LLC is the general partner of KKR Associates 2006 L.P. KKR Fund Holdings L.P. is the designated member of KKR 2006 GP LLC. KKR Fund Holdings GP Limited is a general partner of KKR Fund Holdings L.P. KKR Group Holdings L.P. is a general partner of KKR Fund Holdings L.P. and |
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the sole shareholder of KKR Fund Holdings GP Limited. KKR Group Limited is the sole general partner of KKR Group Holdings L.P. KKR & Co. L.P. is the sole shareholder of KKR Group Limited. KKR Management LLC is the sole general partner of KKR & Co. L.P. Henry R. Kravis and George R. Roberts are the designated members of KKR Management LLC. In addition, Messrs. Kravis and Roberts have been designated as managers of KKR 2006 GP LLC by KKR Fund Holdings L.P. In such capacities, each of the aforementioned entities and individuals may be deemed to have voting and dispositive power with respect to the shares held by Samson Aggregator L.P. but each such entity and individual disclaims beneficial ownership of the shares held by Samson Aggregator L.P. The address of each of the entities listed in this footnote is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, New York, New York 10019. |
(4) | JD Rockies Resources Limited is a 100% wholly-owned subsidiary of ITOCHU Corporation. Its address is 1300 Post Oak Boulevard, Suite 1101, Houston, Texas 77056. The President and Chief Executive Officer of ITOCHU Corporation is Masahiro Okafuji. In such capacity, Mr. Okafuji may be deemed to have voting and dispositive power with respect to shares held by JD Rockies Resources Limited, but he disclaims beneficial ownership of the shares held by JD Rockies Resources Limited. The officers of ITOCHU Corporation, including its President and Chief Executive Officer, are subject to the oversight of a board of directors. |
(5) | Mr. Delaney is a member of our Board of Directors and serves as a Managing Director of the investment manager of the funds affiliated with Crestview Partners II GP, L.P. and is a member of the investment committee of Crestview Partners II GP, L.P. Mr. Delaney disclaims beneficial ownership of the shares held by Samson Aggregator L.P. except to the extent of his pecuniary interest therein. |
(6) | Each of Ms. Farley and Messrs. Freiman, Rockecharlie and Smidt is a member of our Board of Directors and serves as an investment or advisory professional of Kohlberg Kravis Roberts & Co. L.P. and/or one or more of its affiliates. Each of Ms. Farley and Messrs. Freiman, Rockecharlie and Smidt disclaims beneficial ownership of the shares held by Samson Aggregator L.P. except to the extent of any pecuniary interest such director may have therein. |
(7) | Each of Messrs. Mori and Watanabe is a member of our Board of Directors, and Mr. Mori serves as an executive of ITOCHU Corporation and/or one or more of its affiliates. Each of Messrs. Mori and Watanabe disclaims beneficial ownership of the shares held by JD Rockies Resources Limited except to the extent of any pecuniary interest such director may have therein. |
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ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Arrangements with Our Executive Officers
Management Stockholders Agreements
Following the consummation of the Acquisition, we adopted the 2011 Plan for our employees and directors. The 2011 Plan and agreements related thereto are designed to more closely align our employees interests with those of our stockholders and to incentivize our employees to remain in our service by providing them with an opportunity to acquire equity interests in us. In connection with the grant of equity awards under the 2011 Plan to our employees, such employees are required to enter into a stockholders and certain related agreements, which establish the terms of the respective awards and certain related matters. A summary of certain of these provisions is provided below.
2012 Agreements
Put Rights. If the employees employment is terminated due to death or disability, she or he has the right, for a specified period following the termination date, to cause us to purchase on one occasion all, but not less than all, of the shares of our common stock held by her or him (whether or not acquired through the exercise of an option) at the fair market value of such shares on the purchase date. If the employees employment is terminated by us without cause, or the employee resigns with good reason prior to December 21, 2015 and we do not exercise the call right described below, she or he has the right, for a specified period following the termination date, to cause us to purchase on one occasion all, but not less than all, of the shares of our common stock held by her or him (whether or not acquired through the exercise of an option) at the fair market value of such shares. If, prior to December 21, 2015 and we do not exercise the call right described below, the employees employment is terminated by us for cause or the employee resigns without good reason, she or he has the right, for a specified period following the termination date, to cause us to purchase on one occasion all, but not less than all, of the shares of our common stock held by her or him (whether or not acquired through the exercise of an option) at the lesser of fair market value and the price paid for such shares by the employee.
Liquidity Program. Beginning in 2016 and each calendar year thereafter, each employee who is still employed with us at such time and each employee who (1) was terminated without cause, (2) resigns for good reason or (3) resigns without good reason on or after June 21, 2015, has the right to cause us to purchase all or any portion of the (i) stock purchased by the employee, and (ii) shares acquired upon exercise of options; provided, however, the employee may not offer to sell in any one calendar year more than 25% of the total amount of options granted to the employee under the 2011 Plan.
Call Rights. If the employees employment is terminated by us with cause or the employee effects a transfer of stock that is prohibited under the stockholders agreement, then we have the right for a specified period following the applicable event to repurchase from the employee (or her or his permitted transferees) any or all shares held by her or him at the lesser of fair market value and the purchase price paid for such shares by the employee and all options will be terminated without any payment. If the employees employment is terminated by us without cause, or the employee resigns with good reason, then we have the right to repurchase from the employee (or her or his permitted transferees) any or all shares held by her or him at the greater of fair market value or the price paid by the employee for the shares. If the employees employment is terminated due to death or disability, then we have the right to repurchase from the employee (or her or his permitted transferees) any or all shares held by her or him at fair market value. If the employee resigns without good reason before June 21, 2015, then we have the right to repurchase from the employee (or her or his permitted transferees) any or all purchased shares held by her or him at the lesser of fair market value and the price paid for such shares and to purchase shares acquired pursuant to exercise of options at the lesser of fair market value and the option exercise price. If the employee resigns without good reason on or after June 21, 2015, then we have the right to repurchase from the employee (or her or his permitted transferees) any or all purchased shares held by her or him at fair market value.
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Call Rights True-Up Payment. In addition, in the event of an employees termination by us without cause or a resignation with good reason within 180 days immediately preceding an initial public offering of our common stock or a change in control where we have exercised our call right and the per share consideration paid for our common stock in such transaction is greater than the fair market value paid upon the exercise of the call right, then within ten business days following the consummation of such initial public offering or change in control transaction, we will pay the terminated employee an amount equal to the delta between the price at the time of the transaction and the price at the time the call right was exercised.
Restrictive Covenants. As a condition of purchasing our common stock and receiving the options, our employees are subject to certain restrictive covenants, as further described under Part III, Item 11Executive CompensationNarrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 Table.
2013 Agreements
In connection with the grant of option awards under the 2011 Plan in fiscal 2013, our employees were required to enter into an employee stockholders agreement, the terms of which are substantially similar to the terms of the 2012 agreement described above, except that the 2013 agreement does not contain provisions relating to the liquidity program and call rights true-up payment described above, contains different provisions relating to the non-compete covenant and remedies for breach of restrictive covenants and, in certain instances, contains different trigger dates for call rights in the event the employee resigns without good reason. See Part III, Item 11Executive CompensationNarrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 Table.
Repurchase of Shares
In February 2014, the Company offered to repurchase shares of our common stock at a price per share equal to the initial cost basis of such shares from current employees who had previously purchased shares. Pursuant to this offer, we paid approximately $0.2 million and $0.4 million in March 2014 to repurchase shares from Messrs. Cook and Boudreaux, respectively, who were the only executive officers who held purchased shares.
Consulting Agreement, Syndication Fee Agreement and Indemnification Agreement
In connection with the Acquisition, Samson Resources Corporation entered into a consulting agreement with certain affiliates of KKR, ITOCHU and the other initial equity investors, pursuant to which such entities provide management services to us and our affiliates. Under this agreement, we (i) pay a management fee to such entities that increases 5% annually, which resulted in aggregate payments of $22.1 million for the year ended December 31, 2014, (ii) will pay customary fees charged by such entities in connection with services rendered in respect of structuring equity or debt financing with respect to any acquisition, divestiture or other transaction, initial public offering or a debt or equity financing involving the Company and (iii) will reimburse out-of-pocket expenses incurred by such entities in connection with the provisions of services pursuant to the consulting agreement. The consulting agreement also provides for a termination fee based on the net present value of future payment obligations under the consulting agreement in certain circumstances in which the consulting agreement is terminated by us. In addition, we paid a one-time transaction fee under the consulting agreement of approximately $89.4 million in the aggregate to these entities for financial advisory and other services provided in connection with the Acquisition and related transactions. In March 2015, the shareholders consented to the extension of time for the payment of the quarterly management fee until the earlier of (i) September 30, 2015 and (ii) such time as the shareholders determine to reinstate such payment. The extension does not change the amount of management fee incurred pursuant to the consulting agreement.
Moreover, at the time of the Acquisition, we entered into a syndication fee agreement with an affiliate of KKR, pursuant to which we paid approximately $20.6 million to such entity for syndication services provided with respect to the Acquisition and the related transactions. In connection with entering into the consulting and
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syndication fee agreements, we also entered into a separate indemnification agreement with affiliates of KKR, ITOCHU and the other initial equity investors, which provides customary exculpation and indemnification provisions in favor of each such entity and its affiliates in connection with the services provided to us under the consulting and syndication fee agreements.
Investors Stockholders Agreement and Registration Rights Agreement
In connection with the Acquisition, the Company entered into a stockholders agreement with Samson Aggregator and JD Rockies. Samson Aggregator is a limited partnership indirectly owned by investment funds associated with KKR and certain other co-investors, including investment funds affiliated with Crestview Partners II GP, L.P. and Natural Gas Partners IX, L.P., and JD Rockies is a wholly-owned subsidiary of ITOCHU. The stockholders agreement, which was amended and restated in January 2012, provides for, among other things:
| prior to our initial public offering, the right of the Principal Stockholders to designate all of our directors, with, based on the current ownership of the Principal Stockholders, JD Rockies being entitled to designate two directors and Samson Aggregator being entitled to designate all remaining directors; |
| following our initial public offering, the right of the Principal Stockholders to nominate directors for all of our board seats, with, based on the current ownership of the Principal Stockholders, JD Rockies being entitled to nominate two directors and Samson Aggregator being entitled to nominate all remaining directors; |
| certain limitations on the transfer of shares of our common stock; |
| tag-along and drag-along rights with respect to certain transactions; and |
| preemptive rights exercisable in connection with certain equity issuances of the Company or its subsidiaries prior to or in connection with our initial public offering. |
At the closing of the Acquisition, Samson Resources Corporation, Samson Aggregator and JD Rockies entered into a registration rights agreement with respect to the Principal Stockholders investment in Samson Resources Corporation. The registration rights agreement provides for, among other things, certain demand and piggyback registration rights as well as related indemnification provisions.
Secondment Agreement
On December 21, 2011, Samson Resources Corporation entered into a secondment agreement with ITOCHU. The secondment agreement gives ITOCHU the right to send one vice president and three junior level employees to work for us. The seconded employees will be subject to the exclusive supervision and control of our officers and employees. However, at all times the ITOCHU employees will remain employees of, and receive their salaries and benefits from, ITOCHU. Pursuant to the terms of the secondment agreement and certain related arrangements, ITOCHU had sent three secondees to work for us as of December 31, 2014. This secondment agreement will continue until the later of (i) the tenth anniversary after entering into the secondment agreement or (ii) such time that ITOCHU and its affiliates own, in the aggregate, less than 14% of the equity of Samson Resources Corporation.
Gas Offtake Rights Agreement
In connection with the Acquisition, ITOCHU, for itself and its subsidiary Trademark Merchant Energy, LLC (Trademark), entered into a Gas Offtake Rights Agreement (the Offtake Agreement) with Samson Resources Corporation and its subsidiary, Samson Resources Company. In 2013, the Offtake Agreement was assigned to another ITOCHU affiliate, IPC (USA), Inc. (IPC). The Offtake Agreement will expire on December 19, 2021, unless earlier terminated in accordance with its terms. Under the Offtake Agreement, IPC
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has the option to bid on and acquire up to certain agreed-upon percentages of Samsons natural gas production available for term sale and delivered by Samson to a limited number of selected delivery points. Twice a year Samson must provide IPC with an estimate of the quantities of natural gas that Samson believes will be available for term sale at these delivery points in the coming period. IPC then has the option to commit to acquire certain quantities of such natural gas at any delivery point(s) during the applicable period. In the event IPC commits to acquire any quantity of such natural gas at any selected delivery point, IPC and Samson shall then negotiate an arms-length price to be paid at the applicable delivery point(s) by IPC for such natural gas over the applicable period, with the price referencing Inside FERCs Gas Market Report and/or Platts Gas Daily, Daily Price Survey. The negotiated price must then be submitted to and approved by a majority of the Board of Directors of Samson Resources Corporation (excluding any directors on the Board of Directors that are affiliated with ITOCHU) and a majority of the Board of Directors of IPC. In the event that IPC and Samson cannot agree upon a price, or if the respective Boards of either ITOCHU or Samson do not approve of the negotiated price, then IPC must either (i) withdraw its bid in its entirety or (ii) agree to pay the highest pricing that Samson may receive from independent third parties through bids for Samsons natural gas for the applicable period at the applicable delivery point(s). All quantities of natural gas delivered by Samson and acquired by IPC under the Offtake Agreement shall be governed by the terms of an agreed upon North American Energy Standards Board Base Contract for Sale and Purchase of Natural Gas, Version 6.3.1 and published in September 2006.
There were approximately $2.1 million in receipts under the Offtake Agreement for the year ended December 31, 2014.
Other Relationships and Transactions
KKR Capstone Consulting, LLC (Capstone) is a consulting company of operational professionals that works exclusively with KKRs portfolio company management teams to enhance and strengthen operations in KKRs portfolio companies. During the year ended December 31, 2014, we paid approximately $0.5 million to Capstone for consulting services it provided to us.
Since 2009, we have, from time to time, engaged the services of Alliant Insurance Services, Inc. (Alliant), an insurance brokerage firm. In 2012, one or more affiliates of KKR acquired a controlling ownership interest in Alliant. During the year ended December 31, 2014, we paid $0.3 million in fees to Alliant for insurance brokerage services.
We have, from time to time, engaged Select Energy Services, LLC and its subsidiary, Peak Oilfield Services LLC, for water hauling, tank rental and other well-site water management and equipment rental services. Select Energy Services, LLC is an affiliate of Crestview Partners II GP, L.P. Mr. Robert Delaney, one of our directors, is a managing director of the investment manager of the funds affiliated with Crestview Partners II GP, L.P., which indirectly owns interests in Samson Aggregator, and serves as a director of Select Energy Services, LLC. We paid approximately $0.7 million in the aggregate to Select Energy Services, LLC and Peak Oilfield Services LLC for the year ended December 31, 2014.
We also, from time to time, purchase pipe and pumping supplies from Bell Supply Company LLC, which is an affiliate of Crestview Partners II GP, L.P. Mr. Delaney serves on the board of directors of the parent to Bell Supply Company LLC. For the year ended December 31, 2014, we paid approximately $2.1 million for supplies from Bell Supply Company LLC.
In March 2015, we completed the sale of certain of our oil and gas assets to an entity affiliated with Natural Gas Partners in exchange for approximately $48.0 million. Investment funds affiliated with Natural Gas Partners IX, L.P. indirectly own interests in Samson Aggregator.
The Company is party to an agreement with CoreTrust Purchasing Group (CoreTrust), a group purchasing program that maintains relationships with certain vendors, from which participating companies may purchase products or services pursuant to the terms of the purchasing program. Since April 2013, the Company has, from
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time to time, purchased certain products and services from various vendors through the CoreTrust purchasing program. An affiliate of KKR has an arrangement with CoreTrust that permits certain KKR affiliates, including the Company, the benefit of utilizing the CoreTrust group purchasing program. CoreTrust receives payment of fees for administrative and other services provided by CoreTrust from certain vendors based on the products and services purchased by the Company and CoreTrust pays certain fees to the KKR affiliate. In addition, one or more affiliates of KKR have an indirect, minority ownership interest in CoreTrust.
Each of KKR, ITOCHU and the other co-investors, either directly or through affiliates, has ownership interests in a broad range of portfolio companies with whom we may from time to time enter into commercial transactions in the ordinary course of business. Except to the extent described above, we believe that none of our transactions or arrangements with such portfolio companies is significant enough to be considered material to KKR, ITOCHU, the other co-investors or to our business.
Procedures for Review and Approval of Related Person Transactions
A related person transaction is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A related person means:
| executive officers, directors or nominees for director of the Company; |
| beneficial owners of more than five percent of the Companys common stock; and |
| any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of such executive officer, director, nominee for director or beneficial owner and any other person (other than a tenant or employee) sharing the household of such executive officer, director, nominee for director or beneficial owner. |
Our Board of Directors has adopted a written related person transaction policy. Pursuant to this policy, our management is responsible for informing the Audit Committee of the Board of Directors of Samson Resources Corporation of any existing or proposed related person transaction as well as information relating to any such transaction, subject to certain exceptions. The Audit Committee then reviews all related person transactions and either approves, ratifies or disapproves the entry into a particular related person transaction, subject to certain limited exceptions. The Audit Committee will not approve or ratify a related person transaction unless it determines in good faith that, upon consideration of all relevant information, the related person transaction is in, or is not inconsistent with, the best interests of the Company. In determining whether to approve or disapprove entry into a related person transaction, the Audit Committee takes into account all relevant facts and circumstances, including without limitation:
| the nature of the related persons interest in the transaction; |
| the material terms of the transaction; |
| the importance of the transaction both to the Company and the related person; |
| whether the transaction would likely impair the judgment of a director or executive officer to act in the best interest of the Company; and |
| whether the value and terms of the transaction are substantially similar as compared to those of similar transactions previously entered into by the Company with non-related persons, if any. |
Director Independence
Our Principal Stockholders, Samson Aggregator and JD Rockies, currently beneficially own, in the aggregate, substantially all of the outstanding shares of our common stock. Samson Aggregator is a limited partnership indirectly owned by investment funds associated with KKR and certain other co-investors, including
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investment funds affiliated with Crestview Partners II GP, L.P. and Natural Gas Partners IX, L.P. JD Rockies is a wholly-owned subsidiary of ITOCHU. See Part III, Item 12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The Principal Stockholders are party to a stockholders agreement with us, pursuant to which JD Rockies is currently entitled to designate two directors and Samson Aggregator is entitled to designate all remaining directors on the Board. Messrs. Mori and Watanabe serve as the director designees of JD Rockies. Accordingly, the Principal Stockholders control our Board of Directors and, as a result, control our management and policies. For additional information regarding the stockholders agreement, see Investors Stockholders Agreement and Registration Rights Agreement.
We are not listed on a national securities exchange, and therefore we are not subject to the director independence requirements of any such exchange. Because all of our directors were appointed pursuant to the terms of the stockholders agreement described above and are employed by, or otherwise have a material relationship with, us or an affiliate or significant investor of the Principal Stockholders, none of our directors would be considered independent as defined in the federal securities laws or the rules of The New York Stock Exchange or the Nasdaq Stock Market.
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ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
Aggregate fees for professional services rendered to us by Deloitte for the years ended December 31, 2014 and 2013 were as follows (in thousands):
Year Ended December 31, | ||||||||
2014 | 2013 | |||||||
Audit fees(1) |
$ | 2,910 | $ | 2,854 | ||||
Audit-related fees(2) |
337 | | ||||||
Tax fees(3) |
120 | 143 | ||||||
All other fees |
| | ||||||
|
|
|
|
|||||
Total |
$ | 3,367 | $ | 2,997 | ||||
|
|
|
|
(1) | Audit fees for the year ended December 31, 2014 and 2013 were for professional services rendered in connection with: (a) the audits of our consolidated financial statements (b) the reviews of our quarterly condensed consolidated financial statements and (c) the review of other filings with the Securities and Exchange Commission, including review and preparation of registration statements and consents. |
(2) | Audit-related fees for the year ended December 31, 2014 represent fees for professional services provided in connection with other assurance and related services, including carve-out audits pertaining to potential business acquisitions/dispositions. |
(3) | Tax fees represent estimated fees for tax return preparation and consultation on tax matters. |
The Audit Committee is responsible for approving in advance any services to be performed by the independent registered public accounting firm. Each of these services must receive specific pre-approval by the Audit Committee unless the Audit Committee has provided general pre-approval for such category of services in accordance with policies and procedures that comply with applicable laws and regulations. All fees for 2014 and 2013 set forth in the table above were pre-approved by the Audit Committee, which determined that such services would not impair the independence of the auditor and would be consistent with the SECs rules on auditor independence.
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ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
Our audited consolidated financial statements are listed under Index to Consolidated Financial Statements beginning on page F-1 of this report. All schedules are omitted because they are either not applicable or the required information is shown in the financial statements or notes thereto.
(a)(3) Exhibits
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
2.1 |
Stock Purchase Agreement among Samson Resources Corporation (f/k/a Tulip Acquisition Corporation), Samson Investment Company and the selling stockholders named therein, dated as of November 22, 2011. ** | S-4 | 333-186686 | 2.1 | 2/14/2013 | | ||||||
2.2 |
Amendment No. 1 dated December 12, 2011, to Stock Purchase Agreement dated as of November 22, 2011 among Samson Resources Corporation (f/k/a Tulip Acquisition Corporation) and Samson Investment Company and the selling stockholders named therein. | S-4 | 333-186686 | 2.2 | 2/14/2013 | | ||||||
2.3 |
Letter Agreement dated March 19, 2012, to Stock Purchase Agreement dated as of November 22, 2011 among Samson Resources Corporation (f/k/a Tulip Acquisition Corporation) and Samson Investment Company and the selling stockholders named therein. | S-4 | 333-186686 | 2.3 | 2/14/2013 | | ||||||
2.4 |
Letter Agreement dated June 21, 2012, to Stock Purchase Agreement dated as of November 22, 2011 among Samson Resources Corporation (f/k/a Tulip Acquisition Corporation) and Samson Investment Company and the selling stockholders named therein. | S-4 | 333-186686 | 2.4 | 2/14/2013 | | ||||||
2.5 |
Purchase and Sale Agreement between Samson Resources Company, as seller, and Continental Resources, Inc., as buyer, dated as of November 6, 2012. ** | S-4 | 333-186686 | 10.11 | 2/14/2013 | |
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Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
3.1 |
Amended and Restated Certificate of Incorporation of Samson Resources Corporation dated December 20, 2011. | S-4 | 333-186686 | 3.1 | 2/14/2013 | | ||||||
3.2 |
Amended and Restated Articles of Incorporation of Samson Investment Company dated December 21, 2011. | S-4 | 333-186686 | 3.2 | 2/14/2013 | | ||||||
3.3 |
Amended and Restated Bylaws of Samson Resources Corporation as of August 1, 2012. | S-4 | 333-186686 | 3.18 | 2/14/2013 | | ||||||
3.4 |
Amended Bylaws of Samson Investment Company as of December 30, 2011. | S-4 | 333-186686 | 3.19 | 2/14/2013 | | ||||||
4.1 |
Indenture dated as of February 8, 2012 among Samson Investment Company, the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee. | S-4 | 333-186686 | 4.1 | 2/14/2013 | | ||||||
4.2 |
First Supplemental Indenture, dated as of January 29, 2013, among Samson Resources Corporation, Samson Investment Company and Wells Fargo Bank, National Association, as trustee. | S-4/A | 333-186686 | 4.2 | 5/13/2014 | | ||||||
4.3 |
Registration Rights Agreement, dated as of February 8, 2012, by and among Samson Investment Company, the several guarantors named therein and J.P. Morgan Securities LLC as representative of the initial purchasers named therein. | S-4 | 333-186686 | 4.2 | 2/14/2013 | | ||||||
4.4 |
Amendment to the First Supplemental Indenture, dated as of July 21, 2014, among Samson Resources Corporation, Samson Investment Company and Wells Fargo Bank, National Association, as trustee. | S-4/A | 333-186686 | 4.4 | 7/21/2014 | |
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Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.1 |
Credit Agreement, dated as of December 21, 2011, among Samson Investment Company, as the Borrower, the several Lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Collateral Agent, Swingline Lender and a Letter of Credit Issuer, Wells Fargo Bank, N.A., as Syndication Agent, and J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Lead Arrangers and J.P. Morgan Securities LLC, Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, BMO Capital Markets Corp., Barclays Capital, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Mizuho Corporate Bank, Ltd. and RBC Capital Markets as Joint Bookrunners, KKR Capital Markets LLC, as Joint Manager and Arranger. | X | ||||||||||
10.2 |
First Amendment to Credit Agreement among Samson Investment Company, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, dated as of August 6, 2012. | S-4 | 333-186686 | 10.2 | 2/14/2013 | | ||||||
10.3 |
Second Amendment Agreement to Credit Agreement among Samson Investment Company, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Collateral Agent, Swingline Lender and a Letter of Credit Issuer, and the several Lenders party thereto, dated as of September 7, 2012. | X | ||||||||||
10.4 |
Third Amendment Agreement to Credit Agreement among Samson Investment Company, as the Borrower, the Guarantors party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the several Lenders party thereto, dated as of November 14, 2013. | S-4/A | 333-186686 | 10.4 | 5/13/2014 | |
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Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.5 |
Fourth Amendment Agreement to Credit Agreement among Samson Investment Company, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the several Lenders party thereto, dated as of May 9, 2014. | S-4/A | 333-186686 | 10.5 | 5/13/2014 | | ||||||
10.6 |
Fifth Amendment and Waiver Agreement to Credit Agreement among Samson Investment Company, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the several Lenders party thereto, dated as of March 18, 2015. | X | ||||||||||
10.7 |
Second Lien Term Loan Credit Agreement, dated as of September 25, 2012, among Samson Investment Company, as the Borrower, the several lenders from time to time party thereto, Bank of America, N.A., as Administrative Agent and Collateral Agent, Credit Suisse Securities (USA) LLC, as Syndication Agent, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Wells Fargo Securities, LLC, BMO Capital Markets Corp., Barclays Bank PLC, Citigroup Global Markets Inc., RBC Capital Markets and Mizuho Corporate Bank, Ltd., as Joint Bookrunners, and KKR Capital Markets LLC, as Joint Manager and Arranger. | X | ||||||||||
10.8 |
Amendment No. 1, dated as of December 18, 2013, to the Second Lien Term Loan Credit Agreement, dated as of September 25, 2012, among Samson Investment Company, as the Borrower, the Lenders party thereto, Bank of America, N.A., as Administrative Agent and Collateral Agent, and the various other parties thereto. | S-4/A | 333-186686 | 10.7 | 5/13/2014 | |
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Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.9 |
Letter Agreement between Samson Resources Corporation, Kohlberg Kravis Roberts & Co. L.P., NGP Energy Capital Management, L.L.C., Crestview Advisors, L.L.C. and JD Rockies Resources Limited, dated December 21, 2011. | S-4 | 333-186686 | 10.10 | 2/14/2013 | | ||||||
10.10 |
Syndication Fee Agreement, dated as of December 21, 2011, between KKR Capital Markets LLC and Samson Resources Corporation. | S-4/A | 333-186686 | 10.9 | 5/13/2014 | | ||||||
10.11 |
Indemnification Agreement, dated as of December 21, 2011, among Samson Resources Corporation, Samson Investment Company, Samson Aggregator L.P., Samson Aggregator GP LLC, JD Rockies Resources Limited, Kohlberg Kravis Roberts & Co. L.P., NGP Energy Capital Management, L.L.C. and Crestview Advisors, L.L.C. | S-4/A | 333-186686 | 10.10 | 5/13/2014 | | ||||||
10.12 |
Samson Resources Corporation 2011 Stock Incentive Plan. | S-4 | 333-186686 | 10.12 | 2/14/2013 | | ||||||
10.13 |
Samson Resources Corporation 2011 Stock Incentive Plan, as amended on May 13, 2013. | S-4/A | 333-186686 | 10.13 | 5/13/2014 | | ||||||
10.14 |
Samson Investment Company Form of Change of Control Agreement. | S-4 | 333-186686 | 10.13 | 2/14/2013 | | ||||||
10.15 |
Samson Resources Corporation Form of Management Stockholders Agreement (2012). | S-4 | 333-186686 | 10.14 | 2/14/2013 | | ||||||
10.16 |
Samson Resources Corporation Form of Employee Stockholders Agreement (2012). | S-4 | 333-186686 | 10.15 | 2/14/2013 | | ||||||
10.17 |
Samson Resources Corporation Form of Option Award Agreement (2012). | S-4 | 333-186686 | 10.16 | 2/14/2013 | | ||||||
10.18 |
Samson Resources Corporation Form of Sale Participation Agreement (2012). | S-4 | 333-186686 | 10.17 | 2/14/2013 | | ||||||
10.19 |
Letter Agreement between Samson Resources Corporation, Samson Investment Company and Michael G. Daniel, dated December 10, 2012. | S-4 | 333-186686 | 10.23 | 2/14/2013 | |
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Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.20 |
Samson Resources Special Agreement between Samson Resources Company and Brian Trimble, effective October 1, 2012. | S-4 | 333-186686 | 10.24 | 2/14/2013 | | ||||||
10.21 |
Samson Resources Special Agreement between Samson Resources Company and Philip W. Cook, effective April 16, 2012. | S-4 | 333-186686 | 10.25 | 2/14/2013 | | ||||||
10.22 |
Letter Agreement between Samson Resources Corporation, Samson Investment Company and David J. Adams, dated December 18, 2012. | S-4 | 333-186686 | 10.26 | 2/14/2013 | | ||||||
10.23 |
Employment Agreement, effective as of April 18, 2013, between Samson Resources Corporation, Samson Investment Company and Randy L. Limbacher. | S-4/A | 333-186686 | 10.23 | 5/13/2014 | | ||||||
10.24 |
Option Award Agreement, dated as of May 20, 2013, between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.24 | 5/13/2014 | | ||||||
10.25 |
Restricted Stock Award Agreement, dated as of May 20, 2013, between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.25 | 5/13/2014 | | ||||||
10.26 |
Executive Stockholders Agreement, dated as of April 18, 2013, between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.26 | 5/13/2014 | | ||||||
10.27 |
Sale Participation Agreement, dated as of April 18, 2013, between Samson Aggregator L.P. and Randy L. Limbacher. | S-4/A | 333-186686 | 10.27 | 5/13/2014 | | ||||||
10.28 |
Special Agreement, effective as of August 1, 2013, by and between Samson Resources Company and Richard E. Fraley. | S-4/A | 333-186686 | 10.28 | 5/13/2014 | | ||||||
10.29 |
Special Agreement, effective as of August 5, 2013, by and between Samson Resources Company and Louis D. Jones. | S-4/A | 333-186686 | 10.29 | 5/13/2014 | | ||||||
10.30 |
Samson Resources Corporation Form of Executive Stockholders Agreement. | S-4/A | 333-186686 | 10.30 | 5/13/2014 | |
123
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.31 |
Samson Resources Corporation Form of Option Award Agreement. | S-4/A | 333-186686 | 10.31 | 5/13/2014 | | ||||||
10.32 |
Samson Resources Corporation Form of Restricted Stock Award Agreement. | S-4/A | 333-186686 | 10.32 | 5/13/2014 | | ||||||
10.33 |
Samson Resources Corporation Form of Sale Participation Agreement. | S-4/A | 333-186686 | 10.33 | 5/13/2014 | | ||||||
10.34 |
Amendment to Employment Agreement, effective as of April 1, 2014, between Samson Resources Corporation, Samson Investment Company and Randy L. Limbacher. | S-4/A | 333-186686 | 10.34 | 6/30/2014 | | ||||||
10.35 |
Amended Option Award Agreement, dated as of March 24, 2014, by and between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.35 | 6/30/2014 | | ||||||
10.36 |
Amended Restricted Stock Award Agreement, dated as of March 24, 2014, by and between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.36 | 6/30/2014 | | ||||||
10.37 |
Restricted Stock Award Agreement, dated as of March 24, 2014, by and between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.37 | 6/30/2014 | | ||||||
10.38 |
Special Agreement, effective as of April 1, 2014, between Samson Resources Corporation and Louis Jones. | S-4/A | 333-186686 | 10.38 | 6/30/2014 | | ||||||
10.39 |
Samson Resources Corporation Change in Control Severance Plan for Officers, effective as of January 1, 2014. | S-4/A | 333-186686 | 10.39 | 6/30/2014 | | ||||||
10.40 |
Form of Amendment to 2013 Restricted Stock Award Agreements. | S-4/A | 333-186686 | 10.40 | 6/30/2014 | | ||||||
10.41 |
Form of Amendment to 2013 and 2012 Stock Option Award Agreements. | S-4/A | 333-186686 | 10.41 | 6/30/2014 | | ||||||
10.42 |
Samson Resources Corporation Form of Restricted Stock Award Agreement (2014). | S-4/A | 333-186686 | 10.42 | 6/30/2014 | |
124
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.43 |
Officer Retention Agreement, effective as of November 14, 2014, by and between Samson Resources Corporation and Randy L. Limbacher. | 10-Q | 333-186686 | 10.1 | 11/14/2014 | | ||||||
10.44 |
Form of Officer Retention Agreement for Other Officers. | 10-Q | 333-186686 | 10.2 | 11/14/2014 | | ||||||
10.45 |
Samson Resources Corporation Voluntary Severance Plan for Officers. | 10-Q | 333-186686 | 10.3 | 11/14/2014 | | ||||||
10.46 |
Amendment to Change-in-Control Severance Plan for Officers. | 10-Q | 333-186686 | 10.4 | 11/14/2014 | | ||||||
10.47 |
Amendment to Samson Resources Corporation 2011 Stock Incentive Plan. | 10-Q | 333-186686 | 10.5 | 11/14/2014 | | ||||||
10.48 |
Form of Special Bonus Agreement. | 10-Q | 333-186686 | 10.6 | 11/14/2014 | | ||||||
10.49 |
Second Amendment to Employment Agreement, effective as of November 14, 2014, between Samson Resources Corporation, Samson Investment Company and Randy L. Limbacher. | 10-Q | 333-186686 | 10.7 | 11/14/2014 | | ||||||
10.50 |
Form of Amendment to Special Agreements. | 10-Q | 333-186686 | 10.8 | 11/14/2014 | | ||||||
10.51 |
Form of Samson Resources Corporation 2015 Performance Bonus Plan. | X | ||||||||||
10.52 |
Form of Bonus Award. | X | ||||||||||
10.53 |
Form of Performance Award. | X | ||||||||||
10.54 |
Form of Samson Resources Corporation 2015 Bonus Plan. | X | ||||||||||
10.55 |
Form of Settlement, Waiver and Release Agreement. | X | ||||||||||
10.56 |
Form of Release Payment. | X | ||||||||||
12.1 |
Computation of Ratio of Earnings to Fixed Charges. | X | ||||||||||
21.1 |
Subsidiaries of Samson Resources Corporation. | X | ||||||||||
23.1 |
Consent of Netherland, Sewell & Associates, Inc. | X |
125
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
31.1 |
Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
31.2 |
Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
32.1 |
Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated March 31, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
32.2 |
Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated March 31, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
99.1 |
Summary Report of Netherland, Sewall & Associates, Inc. relating to December 31, 2014 Reserve Report. | X | ||||||||||
99.2 |
Summary Report of Netherland, Sewall & Associates, Inc. relating to December 31, 2013 Reserve Report. | S-4/A | 333-186686 | 99.5 | 5/13/2014 | | ||||||
99.3 |
Summary Report of Netherland, Sewall & Associates, Inc. relating to December 31, 2012 Reserve Report. | S-4/A | 333-186686 | 99.6 | 5/13/2014 | | ||||||
101.INS |
XBRL Instance Document. | X | ||||||||||
101.SCH |
XBRL Taxonomy Schema Document. | X | ||||||||||
101.CAL |
XBRL Calculation Linkbase Document. | X | ||||||||||
101.LAB |
XBRL Label Linkbase Document. | X | ||||||||||
101.PRE |
XBRL Presentation Linkbase Document. | X | ||||||||||
101.DEF |
XBRL Definition Linkbase Document. | X |
* | Or furnished, in the case of Exhibits 32.1 and 32.2. |
** | The registrant agrees to furnish supplementally a copy of any omitted schedule or exhibit to the agreement to the commission upon request. |
126
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Tulsa, Oklahoma, on March 31, 2015.
SAMSON RESOURCES CORPORATION | ||
BY: | /s/ Philip W. Cook | |
| ||
Philip W. Cook | ||
Executive Vice President and Chief | ||
Financial Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature |
Title |
Date | ||
/s/ Randy L. Limbacher |
Director, Chief Executive Officer and President (Principal Executive Officer) |
March 31, 2015 | ||
Randy L. Limbacher | ||||
/s/ Philip W. Cook |
Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
March 31, 2015 | ||
Philip W. Cook | ||||
/s/ Brian A. Trimble |
Vice President and Chief Accounting Officer (Principal Accounting Officer) |
March 31, 2015 | ||
Brian A. Trimble | ||||
/s/ Jonathan D. Smidt |
Director |
March 31, 2015 | ||
Jonathan D. Smidt | ||||
/s/ Claire S. Farley |
Director |
March 31, 2015 | ||
Claire S. Farley | ||||
/s/ David C. Rockecharlie |
Director |
March 31, 2015 | ||
David C. Rockecharlie | ||||
/s/ Robert V. Delaney, Jr. |
Director |
March 31, 2015 | ||
Robert V. Delaney, Jr. | ||||
/s/ Akihiro Watanabe |
Director |
March 31, 2015 | ||
Akihiro Watanabe | ||||
/s/ Toshiyuki Mori |
Director |
March 31, 2015 | ||
Toshiyuki Mori | ||||
/s/ Brandon A. Freiman |
Director |
March 31, 2015 | ||
Brandon A. Freiman |
127
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Audited Consolidated Financial Statements
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Of Samson Resources Corporation
Tulsa, Oklahoma
We have audited the accompanying consolidated balance sheets of Samson Resources Corporation and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of loss and comprehensive loss, equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Companys internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Samson Resources Corporation and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, at December 31, 2014, the Company is currently experiencing negative impacts to its liquidity resulting from declining industry conditions and increased uncertainty regarding its ability to comply with restrictive loan covenants during 2015. These conditions discussed in Note 1 to the consolidated financial statements raise substantial doubt about the Companys ability to continue as a going concern. Managements plans in regard to these matters are also discussed in Note 1 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ Deloitte & Touche LLP
Tulsa, Oklahoma
March 31, 2015
F-2
SAMSON RESOURCES CORPORATION
(In thousands, except share and per share data)
As of December 31, | ||||||||
2014 | 2013 | |||||||
Assets |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 23,826 | $ | 727 | ||||
Accounts receivable, net |
173,524 | 174,989 | ||||||
Prepaid expenses and other |
11,488 | 11,484 | ||||||
Deferred tax assets |
| 33,152 | ||||||
Derivative assets |
127,743 | | ||||||
|
|
|
|
|||||
Total current assets |
336,581 | 220,352 | ||||||
Property, plant and equipment, net: |
||||||||
Oil and gas properties, full cost method: |
||||||||
Proved properties |
2,553,102 | 2,823,171 | ||||||
Unproved properties not being amortized |
2,269,521 | 3,915,068 | ||||||
Other property and equipment |
291,761 | 302,693 | ||||||
|
|
|
|
|||||
Total property, plant and equipment, net |
5,114,384 | 7,040,932 | ||||||
Derivative assets |
29,734 | 7,381 | ||||||
Deferred charges |
100,673 | 125,816 | ||||||
Other noncurrent assets |
26,940 | 43,205 | ||||||
|
|
|
|
|||||
Total assets |
$ | 5,608,312 | $ | 7,437,686 | ||||
|
|
|
|
|||||
Liabilities and Equity |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 20,091 | $ | 36,267 | ||||
Oil and gas revenues held for distribution |
92,866 | 117,296 | ||||||
Accrued and other current liabilities |
324,630 | 341,234 | ||||||
Derivative liabilities |
5,790 | 40,529 | ||||||
Current deferred income taxes |
18,500 | | ||||||
Debt classified as current (Note 10) |
3,905,000 | | ||||||
|
|
|
|
|||||
Total current liabilities |
4,366,877 | 535,326 | ||||||
Long-term debt, less amount classified as current (Note 10) |
| 3,554,000 | ||||||
Derivative liabilities |
| 11,241 | ||||||
Deferred credits and other long-term liabilities |
99,265 | 66,117 | ||||||
Deferred income tax liabilities |
746,837 | 1,563,975 | ||||||
Cumulative preferred stock subject to mandatory redemption ($0.10 par value, 180,000 shares authorized, issued and outstanding, recorded at redemption value) |
202,808 | 191,035 | ||||||
Commitments and contingencies (Note 18) |
||||||||
Puttable common stock ($0.01 par value, 200,000 and 650,000 shares issued and outstanding at December 31, 2014 and December 31, 2013, respectively) |
1,000 | 3,250 | ||||||
Shareholders equity: |
||||||||
Common stock ($0.01 par value, 2,000,000,000 shares authorized, with 845,400,000 and 835,400,000 shares issued and outstanding at December 31, 2014 and December 31, 2013, respectively) |
8,290 | 8,290 | ||||||
Additional paid-in capital |
4,268,415 | 4,212,793 | ||||||
Accumulated deficit |
(4,129,651 | ) | (2,709,070 | ) | ||||
Accumulated other comprehensive income |
44,471 | 729 | ||||||
|
|
|
|
|||||
Total shareholders equity |
191,525 | 1,512,742 | ||||||
|
|
|
|
|||||
Total liabilities and shareholders equity |
$ | 5,608,312 | $ | 7,437,686 | ||||
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-3
SAMSON RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF LOSS AND
COMPREHENSIVE LOSS
(In thousands)
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Revenues: |
||||||||||||
Natural gas and natural gas liquids sales |
$ | 668,996 | $ | 648,108 | $ | 528,678 | ||||||
Crude oil sales |
427,381 | 493,884 | 517,824 | |||||||||
Commodity derivatives, net |
81,319 | (58,411 | ) | 121,438 | ||||||||
|
|
|
|
|
|
|||||||
Total revenues |
1,177,696 | 1,083,581 | 1,167,940 | |||||||||
|
|
|
|
|
|
|||||||
Operating expenses: |
||||||||||||
Lease operating |
210,161 | 195,918 | 222,597 | |||||||||
Production and ad valorem taxes |
78,453 | 76,256 | 82,651 | |||||||||
Depreciation, depletion, and amortization |
478,740 | 554,010 | 677,978 | |||||||||
Impairment of oil and gas properties |
2,325,346 | 1,817,670 | 2,253,527 | |||||||||
Asset retirement obligation accretion |
4,752 | 4,704 | 4,643 | |||||||||
Restructuring charges |
| | 46,643 | |||||||||
Related party management fee |
22,050 | 21,000 | 20,000 | |||||||||
General and administrative |
175,631 | 131,305 | 151,168 | |||||||||
|
|
|
|
|
|
|||||||
Total operating expenses |
3,295,133 | 2,800,863 | 3,459,207 | |||||||||
|
|
|
|
|
|
|||||||
Operating loss |
(2,117,437 | ) | (1,717,282 | ) | (2,291,267 | ) | ||||||
Interest (expense) income, net |
(91,908 | ) | 15 | 157 | ||||||||
Other expense, net |
(755 | ) | (2,065 | ) | (22 | ) | ||||||
Loss on early extinguishment of debt |
| | (44,815 | ) | ||||||||
|
|
|
|
|
|
|||||||
Loss before income taxes |
(2,210,100 | ) | (1,719,332 | ) | (2,335,947 | ) | ||||||
Income tax benefit |
(789,519 | ) | (613,958 | ) | (805,918 | ) | ||||||
|
|
|
|
|
|
|||||||
Net loss |
$ | (1,420,581 | ) | $ | (1,105,374 | ) | $ | (1,530,029 | ) | |||
|
|
|
|
|
|
|||||||
Other comprehensive income (loss): |
||||||||||||
Unrealized gain (loss) from cash flow hedges, net of tax of $25,131, $(3,205) and $5,502, respectively |
45,252 | (5,763 | ) | 9,893 | ||||||||
Reclassification for settled cash flow hedges, net of tax of $(833), $99 and $(1,991), respectively |
(1,510 | ) | 178 | (3,579 | ) | |||||||
|
|
|
|
|
|
|||||||
Total other comprehensive income (loss), net of tax |
43,742 | (5,585 | ) | 6,314 | ||||||||
|
|
|
|
|
|
|||||||
Total comprehensive loss |
$ | (1,376,839 | ) | $ | (1,110,959 | ) | $ | (1,523,715 | ) | |||
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-4
SAMSON RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
Common Stock | Treasury Stock, at cost |
Additional Paid-in Capital |
Accumulated Deficit |
Accumulated Other Comprehensive Income (Loss) |
Total Shareholders Equity |
|||||||||||||||||||||||
Shares | Amount | |||||||||||||||||||||||||||
Balance as of January 1, 2012 |
829,000 | $ | 8,290 | $ | | $ | 4,139,590 | $ | (73,667 | ) | $ | | $ | 4,074,213 | ||||||||||||||
Net loss |
| | | | (1,530,029 | ) | | (1,530,029 | ) | |||||||||||||||||||
Stock based compensation |
| | | 39,488 | | | 39,488 | |||||||||||||||||||||
Other comprehensive income |
| | | | | 6,314 | 6,314 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Balance as of December 31, 2012 |
829,000 | 8,290 | | 4,179,078 | (1,603,696 | ) | 6,314 | 2,589,986 | ||||||||||||||||||||
Issuance of restricted common stock |
6,800 | | | | | | | |||||||||||||||||||||
Forfeitures of restricted common stock |
(400 | ) | | | | | | | ||||||||||||||||||||
Repurchase of puttable common stock |
| | | 60 | | | 60 | |||||||||||||||||||||
Net loss |
| | | | (1,105,374 | ) | | (1,105,374 | ) | |||||||||||||||||||
Stock based compensation |
| | | 33,655 | | | 33,655 | |||||||||||||||||||||
Other comprehensive loss |
| | | | | (5,585 | ) | (5,585 | ) | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Balance as of December 31, 2013 |
835,400 | 8,290 | | 4,212,793 | (2,709,070 | ) | 729 | 1,512,742 | ||||||||||||||||||||
Issuance of restricted common stock |
10,000 | | | | | | | |||||||||||||||||||||
Repurchase of puttable common stock |
| | | 1,035 | | | 1,035 | |||||||||||||||||||||
Net loss |
| | | | (1,420,581 | ) | | (1,420,581 | ) | |||||||||||||||||||
Stock based compensation |
| | | 54,587 | | | 54,587 | |||||||||||||||||||||
Other comprehensive income |
| | | | | 43,742 | 43,742 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Balance as of December 31, 2014 |
845,400 | $ | 8,290 | $ | | $ | 4,268,415 | $ | (4,129,651 | ) | $ | 44,471 | $ | 191,525 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-5
SAMSON RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating activities: |
||||||||||||
Net loss |
$ | (1,420,581 | ) | $ | (1,105,374 | ) | $ | (1,530,029 | ) | |||
Adjustments to reconcile net loss to net cash provided by operating activities: |
||||||||||||
Commodity derivatives, net |
(81,319 | ) | 58,411 | (121,438 | ) | |||||||
Cash settlements of derivative instruments, net |
(68,500 | ) | (16,944 | ) | 127,142 | |||||||
Stock based compensation expense |
51,518 | 29,273 | 35,606 | |||||||||
Depreciation, depletion and amortization |
478,740 | 554,010 | 677,978 | |||||||||
Loss on sale of other property and equipment |
1,211 | | | |||||||||
Impairment of oil and gas properties |
2,325,346 | 1,817,670 | 2,253,527 | |||||||||
Asset retirement obligation accretion |
4,752 | 4,704 | 4,643 | |||||||||
Accretion of preferred stock not capitalized |
3,230 | | | |||||||||
Amortization of debt cost not capitalized |
7,163 | | | |||||||||
Benefit for deferred income taxes |
(789,783 | ) | (614,411 | ) | (805,918 | ) | ||||||
Loss on early extinguishment of debt |
| | 44,815 | |||||||||
Other noncash items |
| 317 | | |||||||||
Change in operating assets and liabilities: |
||||||||||||
Accounts receivable |
4,271 | (11,072 | ) | 4,320 | ||||||||
Prepaid expenses and other |
(4 | ) | (7,152 | ) | 2,074 | |||||||
Other noncurrent assets |
| (1,578 | ) | (2,957 | ) | |||||||
Accounts payable |
(13,194 | ) | (15,402 | ) | (437,844 | ) | ||||||
Oil and gas revenues held for distribution |
(24,430 | ) | (3,527 | ) | 31,511 | |||||||
Accrued and other current liabilities |
4,561 | 13,497 | 247,381 | |||||||||
Deferred credits and other long-term liabilities |
4,576 | (13,795 | ) | 1,053 | ||||||||
|
|
|
|
|
|
|||||||
Net cash provided by operating activities |
487,557 | 688,627 | 531,864 | |||||||||
|
|
|
|
|
|
|||||||
Investing activities: |
||||||||||||
Purchase of Predecessor business, net of cash |
| | (109,452 | ) | ||||||||
Capital expendituresoil and gas properties |
(883,752 | ) | (1,031,644 | ) | (1,074,832 | ) | ||||||
Capital expendituresother property and equipment |
(27,500 | ) | (49,320 | ) | (44,423 | ) | ||||||
Acquisitionsoil and gas properties |
(57,631 | ) | | | ||||||||
Proceeds from divestituresoil and gas properties |
146,690 | 311,612 | 735,012 | |||||||||
Proceeds from divestituresother property and equipment |
9,892 | 5,071 | | |||||||||
Proceeds from sale of other assets |
| | 3,811 | |||||||||
|
|
|
|
|
|
|||||||
Net cash used in investing activities |
(812,301 | ) | (764,281 | ) | (489,884 | ) | ||||||
|
|
|
|
|
|
|||||||
Financing activities: |
||||||||||||
Proceeds from borrowings of long-term debt |
| | 3,250,000 | |||||||||
Repayment of long-term debt |
| | (2,250,000 | ) | ||||||||
Proceeds from revolver |
539,000 | 556,000 | 520,000 | |||||||||
Repayment of revolver |
(188,000 | ) | (477,000 | ) | (1,640,000 | ) | ||||||
Debt issuance costs |
(967 | ) | (2,693 | ) | (51,945 | ) | ||||||
Issuance of puttable common stock |
| | 12,375 | |||||||||
Repurchase of puttable common stock |
(2,190 | ) | (2,965 | ) | (6,100 | ) | ||||||
|
|
|
|
|
|
|||||||
Net cash provided by (used in) financing activities |
347,843 | 73,342 | (165,670 | ) | ||||||||
|
|
|
|
|
|
|||||||
Net change in cash |
23,099 | (2,312 | ) | (123,690 | ) | |||||||
Cash and cash equivalents at beginning of period |
727 | 3,039 | 126,729 | |||||||||
|
|
|
|
|
|
|||||||
Cash and cash equivalents at end of period |
$ | 23,826 | $ | 727 | $ | 3,039 | ||||||
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-6
SAMSON RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Nature of Operations and Summary of Significant Accounting Policies
Organization and Nature of Operations
We are an independent oil and gas company incorporated in the state of Delaware and headquartered in Tulsa, Oklahoma. We also have corporate offices located in Denver, Colorado and Houston, Texas as well as several field locations throughout our operating areas. We have operations and acreage positions in the Anadarko, Arkoma, Greater Green River, Powder River, San Juan, East Texas and Williston basins.
Unless the context requires otherwise, in this report references to (i) Samson, Company, we, our, and us refer to Samson Resources Corporation and its subsidiaries and (ii) natural gas or gas include natural gas liquids, which we may refer to as NGLs.
Basis of Presentation
On November 14, 2011, Samson Resources Corporation (Samson) was formed for the purpose of acquiring all of the issued and outstanding common stock of Samson Investment Company, which occurred on December 21, 2011 (the Acquisition). The Acquisition was accounted for as a business combination and the assets acquired and liabilities assumed were recorded at estimated acquisition date fair value.
Industry conditions, liquidity, managements plans, and going concern
We have historically funded our operations with operating cash flow, borrowings under our various credit facilities, and asset sales. Our most significant cash outlays relate to our capital program, current period operating expenses, payments under various long term incentive plans, and our debt service obligations described in Note 10.
The market price for oil, natural gas, and NGLs decreased significantly during the fourth quarter of 2014 with continued weakness into the first quarter of 2015. The decrease in the market price for our production directly reduces our operating cash flow and indirectly impacts our other sources of potential liquidity described above. Lower market prices for our production may result in lower borrowing capacity under our revolving credit facility or higher borrowing costs from other potential sources of debt financing as our borrowing capacity and borrowing costs are generally related to the value of our estimated proved reserves. The weakness in product pricing may also impact our ability to negotiate asset sales at acceptable prices.
In addition, declining industry conditions and company performance reduces the likelihood that we comply with certain restrictive covenants contained in our credit facilities. Our restrictive covenants contained in our various credit facilities, along with the consequences of potentially not complying with those restrictive covenants are described in Note 10. On March 18, 2015, we executed an amendment to our revolving credit facility to change the financial performance covenant beginning with the first quarter of 2015 through and including the third quarter of 2015 from the existing 1.5 to 1.0 to 2.75 to 1.0. Beginning October 1, 2015, the financial performance covenant reverts back to a ratio of first lien debt to consolidated EBITDA of not more than 1.5 to 1.0 for the remainder of 2015 and a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 beginning with the first quarter of 2016. In addition, the March 18, 2015 amendment established a liquidity covenant which requires us to maintain minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due in 2020 and the second lien term loan credit facility entered into by our subsidiary, Samson Investment Company. Unless the financial performance and/or the liquidity covenants are amended further or we are successful in implementing one of the strategic alternatives discussed below, we do not expect to remain in compliance with all of our restrictive covenants throughout 2015 or early 2016. The amendment also waived certain restrictions
F-7
related to the form and content of our auditors report for the year ended December 31, 2014 and increased the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of the Companys and its restricted subsidiaries proved reserves.
Collectively, the negative impacts to our liquidity resulting from declining industry conditions and increased uncertainty regarding our ability to comply with restrictive covenants contained in our credit facilities raises substantial doubt about our ability to continue as a going concern. The consolidated financial statements included in this Annual Report on Form 10-K have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern. Our long-term debt with maturities summarized in Note 10 is reflected as a current liability in our consolidated balance sheet at December 31, 2014. The classification as a current obligation is based on the uncertainty regarding our ability to comply with certain restrictive covenants contained in our credit facilities.
We have begun implementing plans designed to improve our liquidity. We have reduced our 2015 capital budget to approximately $156.5 million and have developed plans to reduce long-term recurring operating expenses. We are continuing our efforts to sell certain non-core assets. In March 2015, we closed a transaction to sell certain oil and gas properties in the Arkoma basin for approximately $48.0 million.
Even if we are successful at reducing our costs and increasing our liquidity through asset sales, we do not expect to have sufficient liquidity to satisfy our debt service obligations, meet other financial obligations, and comply with restrictive covenants contained in our various credit facilities. We have engaged advisors to assist with the evaluation of our options to address our liquidity position and strategic alternatives. The strategic alternatives may include, but not be limited to, seeking a restructuring, amendment or refinancing of our outstanding debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the company will be able to successfully restructure its indebtedness, improve our liquidity position, complete any strategic transactions or comply with debt covenant requirements throughout 2015 or beyond.
Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities, and the reported amounts of revenues and expenses. Estimates and assumptions that, in the opinion of management, are significant include oil and natural gas reserves used to compute depletion expense and the full cost ceiling limitation, depletion expense relating to oil and gas properties, allocations of value from unproved properties to proved properties when proved reserves are established or wells are completed, asset retirement obligations, fair value measurements used in the preparation of our consolidated financial statements (such as derivatives, employee stock-based compensation and business combinations), impairments of unproved property, accruals for revenue, expenses and capital expenditures, assumptions used to account for loss contingencies, projected compliance with debt covenant requirements and income taxes. We base our estimates on historical experience and on assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be determined with certainty, and accordingly, these estimates may change as facts and circumstances change. Actual results will differ from the estimates used in the preparation of our consolidated financial statements.
Cash and Cash Equivalents
Cash and cash equivalents consist of cash on hand and on deposit, as well as investments in highly liquid debt instruments with maturities of three months or less.
F-8
Accounts Receivable
Accounts receivable is primarily comprised of amounts billed to other working interest owners for wells we operate and our accrual for estimated uncollected revenues at period end. Accounts receivable is presented net of an allowance for doubtful accounts of $4.9 million at December 31, 2014. We had no allowance for doubtful accounts at December 31, 2013 and no deductions from our allowance for doubtful accounts for the years ended December 31, 2014, 2013 or 2012. We estimate our allowance for doubtful accounts based on existing economic conditions, the financial conditions of our counterparties and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. Historically, we have not had significant write offs associated with billed receivables. In certain circumstances, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Derivative Instruments
We utilize derivative financial instruments including fixed price swap agreements, basis swaps and collars to manage the impact of fluctuations in the market prices of oil, natural gas and NGLs. Our derivatives are entered into with banks that are part of our revolving credit facility, and therefore we do not have any margin requirements. All contracts are settled with cash and do not require the delivery of physical volumes. We do not enter into derivative instruments for speculative or trading purposes.
We recognize all derivatives in the consolidated balance sheets as either an asset or liability measured at fair value unless they qualify for, and we elect, an exemption for our production sales. Changes in the fair value of our derivative financial instruments that do not qualify for the exemption are reported in the consolidated statements of loss and comprehensive loss in commodity derivatives, net (a component of total revenues), except for those derivatives designated as cash flow hedges.
For those derivatives designated as cash flow hedges, changes in fair value for the effective portion of the hedge are deferred in accumulated other comprehensive income until the hedged production is sold, at which time the deferred amounts are reclassified to commodity derivatives, net. Any change in fair value resulting from ineffectiveness is recognized in current period operations within commodity derivatives, net. If it is determined that the derivative no longer qualifies to be designated as a cash flow hedge, then hedge accounting will be discontinued prospectively and future changes in fair value will be recorded in earnings.
Effective January 1, 2015, the Company discontinued hedge accounting on all of its existing commodity cash flow hedge contracts and began accounting for these derivatives using the MTM accounting method. At the time of hedge discontinuation, the net gains and losses deferred in AOCI associated with these contracts were maintained and will be reclassified to earnings over the periods the production impacts earnings.
Concentration of Credit Risk
We operate a substantial portion of our oil and gas properties. As the operator of a property, we make full payment of costs associated with the property and seek reimbursement from the other working interest owners in the property for their share of these costs. Consequently, the ability of our joint interest partners to reimburse us could be adversely affected by negative developments in the oil and gas industry and other factors.
The purchasers of our oil and gas production consist primarily of independent marketers, major oil and gas companies and midstream companies. We perform credit evaluations of the purchasers of our production and periodically monitor their financial condition. We obtain cash escrows, letters of credit or parental guarantees from some of our purchasers. Historically, we have sold our oil and gas production to several purchasers. There were no customers that accounted for more than 10% of our oil and gas revenues for the year ended December 31, 2014. During the years ended December 31, 2013 and 2012, sales to Shell Trading (US) Company
F-9
accounted for approximately 10.9% and 12.6% of our total oil and gas revenues, respectively. All of our derivative transactions have been executed in the over-the-counter-market with large financial institutions that are part of our revolving credit facility. The use of derivative transactions involves the risk that counterparties will be unable to meet the financial terms of such transactions. We periodically monitor the credit ratings of our derivative counterparties. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on their obligation to us under the related contracts or seek bankruptcy protection, it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. Additionally, in challenging economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could result in greater concentration of our exposure to any one counterparty.
Our total cash balances are insured by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per bank per depositor. We had cash balances on deposit at December 31, 2014 and 2013 that exceeded the balance insured by the FDIC in the amount of $52.1 million and $11.1 million, respectively.
Oil and Gas Properties
We utilize the full cost method of accounting for oil and gas properties. As all of our operations reside within the United States, we maintain one cost center and have one reportable segment.
All costs incurred in connection with the acquisition, exploration and development of oil and gas properties are capitalized. Those costs include any internal costs that are directly related to development and exploration activities and capitalized interest associated with certain unproved oil and gas properties with ongoing development activities. All production costs and general and administrative costs are expensed as incurred.
Sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves.
We compute depletion expense associated with proved oil and gas properties using a composite units-of-production method based upon estimates of proved reserve quantities and our costs incurred related to proved developed properties and costs expected to be incurred to develop our proved undeveloped reserves. Proved reserves for barrels of oil and NGLs are converted to equivalent thousand cubic feet (Mcfe) using a 6:1 ratio. The full cost depletion rates per Mcfe of natural gas sold for the years ended December 31, 2014, 2013 and 2012, were $2.33, $2.50 and $3.17, respectively.
Costs associated with unproved properties that have not been impaired and costs associated with uncompleted capital projects are excluded from the depletion base. As proved reserves are established, costs associated with unproved properties become part of our depletion base. We determine the amount of costs to transfer from unproved properties based on our estimate of the potential drilling locations associated with those properties. Costs associated with uncompleted capital projects are included in our depletion base upon completion of the related project.
Unproved properties are assessed at least annually to ascertain whether impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. The impairment test for unproved properties is not based on the estimated fair value of the unproved properties. The impairment assessment includes consideration of our intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are
F-10
transferred to proved properties, become part of our depletion base, and become subject to the full cost ceiling limitation.
At the end of each reporting period, the unamortized net capitalized cost of oil and gas properties (after considering the impact of deferred income taxes) is limited to the sum of (i) the estimated future net revenues from proved properties, calculated using an unweighted arithmetic average of oil and natural gas prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period, discounted at 10% and adjusted for the effects of existing cash flow hedges and (ii) the cost of properties excluded from the depletion base, adjusted for the related income tax effects (Ceiling Test). If the carrying value of our oil and gas properties exceeds the ceiling, impairment expense is recorded after considering income taxes. Impairment expense reduces the carrying value of our oil and gas properties by increasing accumulated depletion.
Other Property and Equipment
Other property and equipment, including gathering systems, saltwater disposal wells, information technology assets, and other field and corporate assets, are recorded at historical cost and are depreciated using the straight-line method over estimated useful lives ranging from 3 to 32 years. As assets are disposed of, the cost and related accumulated depreciation are removed and any resulting gain or loss is included in earnings. Depreciation expense for the years ended December 31, 2014, 2013 and 2012 was $29.2, $33.4 million and $32.4 million, respectively.
Long-lived assets are tested for impairment when events or circumstances indicate that their carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. There were no impairments of our other property and equipment for any of the periods presented.
Deferred Charges
Deferred charges consist of loan origination costs associated with our long term debt. These costs are amortized to interest expense over the life of the related debt agreements using the effective interest method, except for those costs associated with our revolving credit facility, which are amortized straight-line over the term of the facility. Accelerated expense recognition, or gains and losses, may occur upon certain modifications or early extinguishment of our outstanding debt. We recognized a loss of $44.8 million for the year ended December 31, 2012 related to unamortized loan origination costs as a result of the extinguishment of our bridge facility subsequent to the Acquisition.
Asset Retirement Obligation
We record a liability for asset retirement obligations and increase the carrying value of the related asset in the period in which the liability is incurred. Asset retirement obligations primarily relate to the abandonment of oil and natural gas producing facilities and include costs to dismantle and relocate or dispose of wells and related structures. Accretion expense associated with asset retirement obligations is recorded over time. The long term portion of our asset retirement obligations is recorded in deferred credits and other long-term liabilities in our consolidated balance sheets. The current portion of our asset retirement obligations is recorded in accrued and other current liabilities in our consolidated balance sheets.
Cumulative Preferred Stock Subject to Mandatory Redemption
In December 2011, the Company issued 180,000 shares of cumulative redeemable preferred stock. The shares are redeemable at the option of the Company at any time at a per share redemption price equal to the
F-11
liquidation amount of the share plus any accrued and unpaid dividends compounded quarterly to the date of redemption and are mandatorily redeemable on the earliest to occur of July 1, 2022, or the consummation of an initial public equity offering or a change in control, as defined within the agreement. Increases in the redemption amount of our outstanding preferred stock is considered additional interest cost and a portion of the interest cost is capitalized and a portion is recorded as interest expense in our consolidated statements of loss and comprehensive loss.
Stock-Based Compensation
We apply a fair value-based method of accounting for stock-based compensation, which requires compensation cost to be measured based on the fair value of awards on each grant date. Compensation cost is recognized in our financial statements over the vesting period. The amount of compensation cost relating to employees directly involved in oil and gas exploration activities is capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized in lease operating expense and general and administrative expense.
We utilize the Black-Scholes-Merton option pricing model to estimate the grant date fair value of stock options. The model employs various inputs, including the risk-free interest rate, expected volatility, expected term and the fair value of underlying shares. We have utilized historical data and analyzed current information to reasonably estimate the inputs.
We measure the fair value of restricted stock based upon the value of the underlying share at the time of the grant, adjusted for a discount for marketability. The fair value of the underlying share price is estimated utilizing various internal models that rely partly upon observable market data that include cash flows, reserve base and production characteristics for Samson and industry peers.
We recognize stock-based compensation on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and make adjustments as circumstances warrant.
As described in Note 14, during the year ended December, 31, 2014, the Compensation Committee of the Board of Directors approved certain compensation actions relating to the Companys officers, which included granting temporary put and call rights associated with previously granted stock compensation awards. Consequently, the vested portion of those awards is reflected as a liability in our consolidated balance sheet at December 31, 2014 based on the estimated settlement amount. The estimated settlement amount is remeasured at each reporting date until the temporary put and call rights are exercised or expire. If the temporary put and call rights expire unexercised, the amounts reflected in current liabilities will be reclassified to equity. Compensation expense associated with the previously issued stock compensation awards is based on the original grant date fair value of the awards as the estimated fair value of the liability at December 31, 2014 is less than the original grant date fair value of the awards. In March 2015, the temporary put and call rights were canceled. Consequently, no liability associated with the temporary put and call rights will be reflected in our consolidated balance sheet subsequent to the cancelation date.
Capitalized Interest
Interest cost associated with our RBL Revolver, Senior Notes, Second Lien Term Loan, Cumulative Preferred Stock, and amortization of loan commitment and debt costs is capitalized for certain unproved oil and gas properties with ongoing development activities. Any interest cost incurred that exceeds the amount capitalized is reflected as interest expense in the consolidated statement of loss and comprehensive loss. We capitalized interest costs of $243.1 million, $341.7 million and $279.7 million during the years ended December 31, 2014, 2013 and 2012, respectively.
F-12
Oil and Gas Revenues Held for Distribution
For certain of our operated oil and gas properties we collect sales proceeds on behalf of other parties who have an interest in the production. These amounts are subsequently distributed based on the interests of these other parties in the well and are included in oil and gas revenues held for distribution in our consolidated balance sheets.
Revenue Recognition
Oil and gas revenues are recognized when production is sold at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. A significant portion of our oil and gas production is sold, with title passing and revenue recognized, at or near our wells under short-term purchase contracts at prevailing prices in accordance with arrangements which are customary in the oil and gas industry. Revenue from the production of oil, natural gas and NGLs on properties in which we have joint ownership is recorded under the sales method. The sales method requires revenue recognition when title is transferred pursuant to the contracts covering our interest in the reserves. Our method of recording natural gas sales allows for recognition of revenue that may be more or less than our share of proportionate production from certain wells. We estimate our aggregate net balancing position to be approximately 9.4 Bcf and 11.3 Bcf overproduced as of December 31, 2014 and 2013, respectively. During such times as our sales exceed our proportionate ownership in a well, such sales are recorded as revenues unless total sales from the well have exceeded our share of estimated total remaining reserves underlying the property at which time such excess is recorded as a liability. We have recorded a liability relating to our overproduced position of $14.6 million (7.4 Bcf) and $14.6 million (8.1 Bcf) at December 31, 2014 and 2013, respectively, which is included in deferred credits and other long-term liabilities in our consolidated balance sheets.
Fair Value Measurements
Certain of our assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. Fair value measurements are classified according to a hierarchy that prioritizes the inputs and assumptions underlying the valuation techniques. This hierarchy consists of three broad levels:
| Level 1Inputs consist of quoted prices in active markets for identical assets and liabilities. When available, we measure our assets and liabilities using Level 1 inputs as they provide the most reliable evidence of fair value. |
| Level 2Inputs consist of quoted prices that are generally observable for the asset or liability, either directly or indirectly. Common examples of these inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active that are nonetheless observable by correlation to observable market pricing or executed transactions. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported observable data levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps. Our valuation models consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instrument, as well as other relevant economic measures. |
| Level 3Inputs are not observable from objective sources and have the lowest priority. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 instruments primarily include over-the-counter basis swaps and collars. Our valuation models consider various inputs including: (i) quoted forward prices for commodities, (ii) time |
F-13
value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although we utilize our counterparties valuations to assess the reasonableness of our prices and valuation techniques, we do not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2. |
Income Taxes
We account for deferred tax assets and liabilities based on the difference between the financial statement and tax basis of assets and liabilities using enacted rates expected to be in effect during the year in which the basis differences reverse. The realizability of deferred tax assets are evaluated and a valuation allowance is established to reduce the deferred tax assets if it is more likely than not that the related tax benefits will not be realized and we are in a net deferred tax asset position. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts.
Recent Accounting Pronouncements
In August 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-15 Presentation of Financial StatementsGoing Concern. ASU 2014-15 provides guidance regarding managements responsibility to evaluate whether there is substantial doubt about an entitys ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for our annual period ending after December 15, 2016, and for all annual and interim periods thereafter. Early application is permitted. We have not determined when we will adopt ASU 2014-15 or the impact the new standard will have on our consolidated financial statements. Upon adoption, we will be required to consider whether there are adverse conditions or events that raise substantial doubt about the Companys ability to continue as a going concern within one year after the date that the financial statements are issued. Adverse conditions or events would include, but not be limited to, negative financial trends, a need to restructure outstanding debt to avoid default, and industry developments.
In May 2014, the FASB issued ASU 2014-09 Revenue from Contracts with Customers. ASU 2014-09 creates a comprehensive framework for the recognition of revenue. ASU 2014-09 requires an entity to (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 is effective beginning on January 1, 2017 for public entities. We are currently evaluating the potential impact of ASU 2014-09 on our consolidated financial statements.
Note 2. Acquisitions and Divestitures
Goodrich Acquisition
On December 22, 2014, we closed on the acquisition of certain oil and natural gas properties from Goodrich Petroleum Company, L.L.C. The acquisition was accounted for as a business combination and the assets acquired and liabilities assumed were recorded at estimated acquisition date fair value. Consideration transferred in the transaction was $57.6 million in cash, subject to customary closing adjustments. The following represents the estimated fair value of net assets acquired in the transaction (in thousands):
Oil and natural gas properties: |
||||
Proved properties |
$ | 44,733 | ||
Unproved properties excluded from amortization |
15,111 | |||
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|
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Total assets acquired |
$ | 59,844 | ||
Fair value of liabilities assumed: |
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Asset retirement obligations |
$ | (2,213 | ) | |
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|
|||
Net assets acquired |
$ | 57,631 | ||
|
|
F-14
The recording of the business combination is preliminary as we are still in the process of determining estimated fair values of acquired assets and liabilities. The estimated fair value of our oil and gas properties is based on reserve information calculated utilizing forward pricing and comparable market transactions. The business combination is not expected to have a material impact to cash flows or results of operations on a pro-forma basis.
Permian Divestitures
In June 2013, we completed the sale of certain oil and gas properties in the Permian Basin for approximately $68.0 million. The net sales proceeds have been reflected as a reduction of oil and gas properties, with no gain or loss recognized.
Williston Divestitures
In December 2012, we closed a transaction in which we sold certain Bakken producing and undeveloped properties in North Dakota, for approximately $650.0 million plus certain customary post-closing adjustments. Also in December 2012, we closed a transaction with a separate counterparty to sell certain Bakken producing and undeveloped properties for $30.0 million plus certain customary post-closing adjustments. The net sales proceeds from these divestitures have been reflected as a reduction of oil and gas properties, with no gain or loss recognized. Approximately $137.8 million of unproved property value was transferred to proved properties as a result of these transactions.
Other Divestitures
In September 2013, we completed the sale of certain oil and gas properties in the Trail Unit of Wyomings Vermillion Basin for approximately $106.7 million. The net sales proceeds have been reflected as a reduction of proved oil and gas properties, with no gain or loss recognized.
For the years ended December 31, 2014 and 2013, we had further divestitures of oil and gas properties in various regions and received total additional proceeds of approximately $146.7 million and $136.9 million, respectively, with no gain or loss recognized.
In March 2015 we closed a transaction to sell certain oil and gas properties in the Arkoma basin for approximately $48.0 million.
Note 3. Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
December 31, 2014 | December 31, 2013 | |||||||
Oil and gas properties: |
||||||||
Proved properties |
$ | 10,569,969 | $ | 8,075,440 | ||||
Unproved properties excluded from amortization |
2,164,708 | 3,789,432 | ||||||
Uncompleted capital project costs excluded from amortization |
104,813 | 125,636 | ||||||
Accumulated depletion |
(8,016,867 | ) | (5,252,269 | ) | ||||
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Net oil and gas properties |
4,822,623 | 6,738,239 | ||||||
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|
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Other property and equipment: |
384,161 | 368,980 | ||||||
Accumulated depreciation |
(92,400 | ) | (66,287 | ) | ||||
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Net other property and equipment |
291,761 | 302,693 | ||||||
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Property, plant and equipment, net of accumulated depletion and depreciation |
$ | 5,114,384 | $ | 7,040,932 | ||||
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F-15
Oil and Gas Properties
We utilize the full cost method of accounting for oil and gas properties. We recorded approximately $1.7 billion, $1.6 billion and $1.3 billion of impairment of unproved properties during the years ended December 31, 2014, 2013 and 2012, respectively, due to acreage expirations, planned divestitures of unproved properties and our assessment of the likelihood that certain acreage positions will be developed.
We capitalize internal costs that are directly related to the acquisition, exploration and development of oil and gas properties. Such capitalized internal costs are included in proved properties and are subject to depletion. We also capitalize interest costs for properties with exploration and development activities. Such capitalized interest costs are included in unproved oil and gas properties and are excluded from amortization. The following table summarizes capitalized internal costs and capitalized interest costs for the periods presented (in thousands):
December 31, 2014 | December 31, 2013 | December 31, 2012 | ||||||||||
Capitalized internal costs, excluding stock compensation |
$ | 30,845 | $ | 37,576 | $ | 35,814 | ||||||
Capitalized stock compensation |
5,410 | 4,382 | 3,882 | |||||||||
Capitalized interest costs |
243,110 | 341,719 | 279,659 | |||||||||
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$ | 279,365 | $ | 383,677 | $ | 319,355 | |||||||
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|
|
During the years ended December 31, 2014, 2013 and 2012, the net capitalized cost of oil and gas properties subject to depletion exceeded the ceiling amount during quarterly ceiling tests. As a result, we recorded impairment expense associated with our oil and gas properties in the amount of $2.3 billion, $1.8 billion and $2.3 billion, respectively. Our pre-tax impairment expense associated with our oil and gas properties for the years ended December 31, 2014, 2013 and 2012 increased (decreased) by $49.7 million, $(11.1) million and $(99.2) million, respectively, as a result of derivatives designated as cash flow hedges.
Note 4. Other Noncurrent Assets
The following table presents the components of other noncurrent assets (in thousands):
December 31, 2014 | December 31, 2013 | |||||||
Tubular and oil and gas equipment |
$ | 18,428 | $ | 38,077 | ||||
Prepaid drilling costs |
4,272 | 1,400 | ||||||
Other |
4,240 | 3,728 | ||||||
|
|
|
|
|||||
$ | 26,940 | $ | 43,205 | |||||
|
|
|
|
Tubular and oil and gas equipment consists of materials and supplies, primarily pipe, held for use in our oil and gas production activities. Tubular and oil and gas equipment is carried at cost.
Prepaid drilling costs are amounts charged to us by our joint venture operators for our working interest share of costs related to anticipated future drilling. The prepaid balance is decreased as drilling occurs and wells are moved to producing status and into our full cost pool.
F-16
Note 5. Accrued and Other Current Liabilities
The following table presents the components of accrued and other current liabilities (in thousands):
December 31, 2014 | December 31, 2013 | |||||||
Accrued interest |
$ | 84,153 | $ | 90,811 | ||||
Accrued capital and other expenditures |
111,099 | 97,838 | ||||||
Accrued compensation and benefits |
51,303 | 37,394 | ||||||
Production and ad valorem taxes |
33,549 | 41,637 | ||||||
Book cash overdrafts |
112 | 26,786 | ||||||
Asset retirement obligation (current portion) |
3,044 | 11,617 | ||||||
Advance payments from and payables to partners |
26,658 | 29,766 | ||||||
Equity compensation awards |
7,798 | | ||||||
Other |
6,914 | 5,385 | ||||||
|
|
|
|
|||||
$ | 324,630 | $ | 341,234 | |||||
|
|
|
|
Note 6. Deferred Credits and Other Long-Term Liabilities
The following table presents the components of deferred credits and other long-term liabilities (in thousands):
December 31, 2014 | December 31, 2013 | |||||||
Asset retirement obligation |
$ | 72,668 | $ | 48,791 | ||||
Gas balancing liability |
14,553 | 14,631 | ||||||
Other long-term liabilities |
12,044 | 2,695 | ||||||
|
|
|
|
|||||
$ | 99,265 | $ | 66,117 | |||||
|
|
|
|
Note 7. Asset Retirement Obligations
Asset retirement obligations primarily relate to producing wells and represent the estimated discounted costs for future dismantlement and abandonment of oil and gas properties. The following table provides a reconciliation of the changes in the estimated asset retirement obligations for the periods presented (in thousands):
Year Ended December 31, 2014 |
Year Ended December 31, 2013 |
Year Ended December 31, 2012 |
||||||||||
Asset retirement obligations as of beginning of period |
$ | 60,408 | $ | 55,228 | $ | 141,200 | ||||||
Liabilities incurred |
6,860 | 4,328 | 1,096 | |||||||||
Liabilities settled |
(6,504 | ) | (4,194 | ) | (985 | ) | ||||||
Disposition of wells |
(5,782 | ) | (2,831 | ) | (1,410 | ) | ||||||
Accretion expense |
4,752 | 4,704 | 4,643 | |||||||||
Change in estimate |
12,277 | | (88,903 | ) | ||||||||
Revisions |
3,701 | 3,173 | (413 | ) | ||||||||
|
|
|
|
|
|
|||||||
Asset retirement obligations as of end of period |
$ | 75,712 | $ | 60,408 | $ | 55,228 | ||||||
|
|
|
|
|
|
F-17
Changes in estimates used to record asset retirement obligations occur when new information becomes available or if our plans change with respect to future retirement activities. Changes may relate to expected future retirement costs or the timing of when retirement activities may occur.
Note 8. Derivative Financial Instruments
Objectives and Strategies
We are exposed to market risk from changes in energy commodity prices related to our crude oil, natural gas and NGL production activities. We utilize commodity-based derivative instruments to manage our exposure to changes in expected future cash flows from forecasted sales of oil, natural gas and NGLs attributable to commodity price risk. These derivatives include fixed price swap agreements, basis swaps and collars containing extension options.
Accounting Treatment
We designated a portion of our commodity derivatives as cash flow hedges of the forecasted sales of our oil and natural gas production. The table below summarizes the various methods in which we account for our derivative instruments and the impact on our consolidated financial statements:
Recognition and Measurement | ||||
Accounting Treatment |
Balance Sheet |
Statement of Loss and Comprehensive Loss | ||
Normal purchase/normal sale |
- Fair value not recorded |
- Change in fair value not recognized in earnings | ||
Mark-to-market |
- Recorded at fair value |
- Change in fair value recognized in earnings | ||
Cash flow hedge |
- Recorded at fair value |
- Ineffective portion of gain or loss on the derivative instrument is recognized in earnings | ||
- Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income |
- Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income into earnings when the forecasted transaction affects earnings |
For cash flow hedges, we formally document all relationships between hedging instruments and hedged items as well as risk-management objectives. We specifically identify the forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships quarterly to determine whether the hedge relationships are highly effective on a retrospective basis. The agreements and contracts designated as cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness could be recognized as a result of locational differences between the hedging derivative and the hedged item and due to changing market conditions.
Derivatives
Our natural gas derivatives settle against the last day prompt month New York Mercantile Exchange (NYMEX) Henry Hub futures price. Our natural gas basis swaps settle against the respective Inside FERC first of the month index. Our crude oil derivatives settle against the calendar month average of the prompt month NYMEX West Texas Intermediate futures price. NGL fixed price swap agreements settle against the respective Mont Belvieu or Conway Oil Price Information Service calendar month averages.
F-18
The following table sets forth our net open derivative positions as of December 31, 2014 for derivatives designated as cash flow hedging instruments:
Natural Gas Fixed Price Swaps | Crude Oil Fixed Price Swaps | |||||||||||||||
Period |
Volume (MMBtu) |
Weighted Average Price ($/MMBtu) |
Volume (MBBls) |
Average Price ($/BBl) |
||||||||||||
2015 |
37,317,000 | $ | 4.09 | 365 | $ | 91.30 | ||||||||||
2016 |
31,535,800 | $ | 4.08 | | $ | | ||||||||||
2017 |
14,600,000 | $ | 3.92 | | $ | |
The following tables set forth our net open derivative positions as of December 31, 2014 for derivatives not designated as cash flow hedging instruments:
Natural Gas Fixed Price Swaps | Crude Oil Fixed Price Swaps | |||||||||||||||
Period |
Volume (MMBtu) |
Weighted Average Price ($/MMBtu) |
Volume (MBBls) |
Average Price ($/BBl) |
||||||||||||
2015 |
24,625,000 | $ | 4.01 | 913 | $ | 90.76 | ||||||||||
2016 |
16,470,000 | $ | 3.97 | | $ | | ||||||||||
2017 |
| $ | | | $ | |
Natural Gas Collars | ||||||||
Period |
Volume (MMBtu) |
Weighted Average Floor/Ceiling Price ($/MMBtu) |
||||||
2015 |
8,200,000 | $ | 4.03/5.20 | |||||
2016(a) |
| |
Ethane Fixed Price Swaps |
Propane Fixed Price Swaps |
Natural Gasoline Fixed Price Swaps |
Butane Fixed Price Swaps |
|||||||||||||||||||||||||||||
Period |
Volume (Tgal) |
Weighted Avg. Price ($/gal) |
Volume (Tgal) |
Weighted Avg. Price ($/gal) |
Volume (Tgal) |
Weighted Avg. Price ($/gal) |
Volume (Tgal) |
Weighted Avg. Price ($/gal) |
||||||||||||||||||||||||
2015 |
5,136 | $ | 0.27 | 3,104 | $ | 1.09 | 1,571 | $ | 2.03 | 1,686 | $ | 1.29 |
(a) | We have entered into natural gas derivative contracts which give counterparties the option to extend certain option contracts currently in place for 2015 for an additional twelve-month period if elected on December 24, 2015. If extended, options covering a notional volume of 10,980,000 MMBtu will exist during 2016 with a floor price of $4.00/MMBtu and a ceiling price of $5.13/MMBtu. |
Financial Statement Presentation
To the extent a legal right to offset exists, we net the value of our derivatives with the same counterparty in the accompanying consolidated balance sheets.
F-19
The following table presents the gross fair value of our derivative instruments as of the dates presented (in thousands):
December 31, 2014 | ||||||||||||||||
Gross Assets | Gross Liabilities | Netting(a) | Net Amount Presented in Consolidated Balance Sheets |
|||||||||||||
Derivatives designated as cash flow hedges: |
||||||||||||||||
Current derivative assets |
$ | 51,905 | $ | | $ | | $ | 51,905 | ||||||||
Noncurrent derivative assets |
21,499 | | (78 | ) | 21,421 | |||||||||||
Current derivative liabilities |
| | | | ||||||||||||
Noncurrent derivative liabilities |
| (78 | ) | 78 | | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives designated as cash flow hedges |
73,404 | (78 | ) | | 73,326 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Derivatives not designated as cash flow hedges: |
||||||||||||||||
Current derivative assets |
97,406 | | (21,568 | ) | 75,838 | |||||||||||
Noncurrent derivative assets |
8,313 | | | 8,313 | ||||||||||||
Current derivative liabilities |
| (27,358 | ) | 21,568 | (5,790 | ) | ||||||||||
Noncurrent derivative liabilities |
| | | | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives not designated as cash flow hedges |
105,719 | (27,358 | ) | | 78,361 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives |
$ | 179,123 | $ | (27,436 | ) | $ | | $ | 151,687 | |||||||
|
|
|
|
|
|
|
|
December 31, 2013 | ||||||||||||||||
Gross Assets | Gross Liabilities | Netting(a) | Net Amount Presented in Consolidated Balance Sheets |
|||||||||||||
Derivatives designated as cash flow hedges: |
||||||||||||||||
Current derivative assets |
$ | 788 | $ | | $ | (788 | ) | $ | | |||||||
Noncurrent derivative assets |
3,070 | | (533 | ) | 2,537 | |||||||||||
Current derivative liabilities |
| (4,484 | ) | 788 | (3,696 | ) | ||||||||||
Noncurrent derivative liabilities |
| (2,725 | ) | 533 | (2,192 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives designated as cash flow hedges |
3,858 | (7,209 | ) | | (3,351 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Derivatives not designated as cash flow hedges: |
||||||||||||||||
Current derivative assets |
4,136 | | (4,136 | ) | | |||||||||||
Noncurrent derivative assets |
11,662 | | (6,818 | ) | 4,844 | |||||||||||
Current derivative liabilities |
| (40,969 | ) | 4,136 | (36,833 | ) | ||||||||||
Noncurrent derivative liabilities |
| (15,867 | ) | 6,818 | (9,049 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives not designated as cash flow hedges |
15,798 | (56,836 | ) | | (41,038 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives |
$ | 19,656 | $ | (64,045 | ) | $ | | $ | (44,389 | ) | ||||||
|
|
|
|
|
|
|
|
(a) | Our derivative assets and liabilities are labeled accordingly in the consolidated balance sheets and are presented on a net basis. We net derivative assets and liabilities when a legally enforceable master netting agreement exists between the counterparty to a derivative contract and us. |
F-20
Cash Flow Hedges
We use derivative instruments to hedge the cash flows associated with the anticipated sales of our oil and natural gas production activities. Accumulated other comprehensive income at December 31, 2014 included $44.5 million, net of tax, related to these cash flow hedges that will be recognized over the next four years as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $29.7 million in gains, net of income tax, over the next twelve months. For derivatives designated as cash flow hedges, the following table presents separately the pretax cash settlements and unrealized gains and losses included in the consolidated statements of loss and comprehensive loss for the periods presented (in thousands):
December 31, | ||||||||||||||
2014 | 2013 | 2012 | Classification | |||||||||||
Net gain (loss) recognized in other comprehensive income due to the derivative movement of the effective portion of cash flow hedges |
$ | 70,383 | $ | (8,968 | ) | $ | 15,395 | AOCI | ||||||
Net gain (loss) reclassified from accumulated other comprehensive income into income due to realized gains (losses) associated with sales of production |
$ | 2,343 | $ | (277 | ) | $ | 5,570 | Commodity Derivatives, net | ||||||
Net gain (loss) recognized in income due to the movement of the ineffective portion of cash flow hedges |
$ | 14,919 | $ | | $ | 1,648 | Commodity Derivatives, net |
For the years ended December 31, 2014, 2013 and 2012, changes in accumulated other comprehensive income for cash flow hedges, net of tax, are detailed below (in thousands). The reclassifications out of accumulated other comprehensive income are included in commodity derivatives, net in the consolidated statements of loss and comprehensive loss.
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Balance, beginning of period |
$ | 729 | $ | 6,314 | $ | | ||||||
Other comprehensive income (loss) before reclassifications |
45,252 | (5,763 | ) | 9,893 | ||||||||
Cash settlements of cash flow hedges reclassified into earnings from accumulated other comprehensive income |
(1,510 | ) | 178 | (3,579 | ) | |||||||
|
|
|
|
|
|
|||||||
Net current period other comprehensive income (loss) |
43,742 | (5,585 | ) | 6,314 | ||||||||
|
|
|
|
|
|
|||||||
Balance, end of period |
$ | 44,471 | $ | 729 | $ | 6,314 | ||||||
|
|
|
|
|
|
Effective January 1, 2015, the Company discontinued hedge accounting on all of its existing cash flow hedge contracts and began accounting for these derivatives using the mark-to-market accounting method. At the time of hedge discontinuation, the net gains and losses deferred in accumulated other comprehensive income associated with these contracts remain and will be reclassified to earnings in the periods the original forecasted production occurs. For the years ending December 31, 2015, 2016 and 2017 the Company expects to reclassify deferred gains on discontinued cash flow hedges of $29.7 million, $11.2 million and $3.5 million, respectively, to oil and gas revenues.
F-21
Note 9. Fair Value Measurements
The following table presents, by level within the fair value hierarchy, our commodity derivative assets and liabilities that are measured at fair value on a recurring basis as of the dates presented (in thousands):
Fair Value Measurement Using: | ||||||||||||||||
Gross Carrying Amount |
Level 1 Inputs | Level 2 Inputs | Level 3 Inputs | |||||||||||||
December 31, 2014 assets (liabilities): |
||||||||||||||||
Derivative assets |
$ | 179,123 | $ | | $ | 173,558 | $ | 5,565 | ||||||||
Derivative liabilities |
$ | (27,436 | ) | $ | | $ | (19,785 | ) | $ | (7,651 | ) | |||||
December 31, 2013 assets (liabilities): |
||||||||||||||||
Derivative assets |
$ | 19,656 | $ | | $ | 15,731 | $ | 3,925 | ||||||||
Derivative liabilities |
$ | (64,045 | ) | $ | | $ | (53,539 | ) | $ | (10,506 | ) |
Management evaluates the methods and assumptions in a third party valuation report as part of our process in estimating the fair value of our derivatives. The following methods and assumptions were used to estimate the fair values in the table above:
Level 2 Fair Value Measurements
DerivativesThe fair value of oil and natural gas commodity swaps has been calculated utilizing quoted market prices that are observable.
Level 3 Fair Value Measurements
DerivativesThe fair value of NGL swaps has been calculated utilizing third party pricing services and discount factors. The fair value of natural gas collars has been calculated utilizing futures prices and market implied volatilities of the underlying futures contracts.
The significant unobservable inputs used in the fair value measurement of the Companys Level 3 derivative contracts are forward NGL price curves and implied NYMEX natural gas volatilities. Significant changes in these unobservable forward NGL price curves would significantly impact the fair value measurements of our NGL swaps. Significant increases or decreases in the market implied volatilities will tend to have a net neutral impact on the fair value measurements of the NYMEX natural gas extendible collars, as the put and the call included in the collar would have directionally opposite changes in value. The following table discloses the significant unobservable inputs used in pricing these derivative contracts.
Commodity |
Fair Value | Valuation Technique |
Unobservable Input |
Range | Weighted Average |
|||||||||||
(In thousands) | ||||||||||||||||
NGL Swaps |
$ | 4,847 | Discounted cash flow | Forward commodity price curve ($/gallon) | $ | 0.15-$1.12(a) | $ | 0.46 | (a) | |||||||
Natural gas collar |
$ | (6,933 | ) | Option Model | Market implied volatilities of underlying futures (%) | 21.8%-34.6%(b) | |
(a) | Represents the market price range and weighted average market price that the Company has determined that market participants would take into account when pricing these NGL swaps. |
(b) | Represents the range of market implied volatilities of the underlying natural gas NYMEX futures that the Company has determined that market participants will use when pricing the NYMEX natural gas extendible collars. |
F-22
The following table presents a reconciliation of changes in the fair value of our financial assets and liabilities classified as Level 3 fair value measurements in the fair value hierarchy for the indicated periods (in thousands):
Derivatives | ||||
Balance at December 31, 2012 |
$ | 4,738 | ||
Total gains or losses: |
||||
Included in earnings |
(12,695 | ) | ||
Included in other comprehensive loss |
160 | |||
Settlements |
1,216 | |||
|
|
|||
Balance at December 31, 2013 |
$ | (6,581 | ) | |
Total gains or losses: |
||||
Included in earnings |
19,734 | |||
Less: Transfers out of Level 3 |
(14,861 | ) | ||
Included in other comprehensive loss |
| |||
Settlements |
(378 | ) | ||
|
|
|||
Balance at December 31, 2014 |
$ | (2,086 | ) | |
|
|
Year Ended December 31, | ||||||||
2014 | 2013 | |||||||
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain (loss) of assets still held |
$ | (1,392 | ) | $ | 3,691 | |||
|
|
|
|
Other Financial Instruments
Our cash and cash equivalents are comprised of bank and money market accounts. The carrying values of our cash and cash equivalents, accounts receivable and accounts payable approximate fair value, primarily due to the short-term nature of these instruments. At December 31, 2014 and December 31, 2013, the estimated fair value of our long-term debt, including debt classified as current and cumulative redeemable preferred stock, was approximately $2.4 billion and $3.8 billion, respectively. Our measurements are based primarily upon quoted trading prices at December 31, 2014 for our Senior Notes and second lien term loan credit facility of 41.5% and 78.6% of par, respectively, and internal models for our RBL Revolver and cumulative redeemable preferred stock and therefore include both Level 2 and Level 3 measurements under the fair value hierarchy.
Note 10. Debt
Total Debt
As of the dates presented, our long-term debt (including debt classified as current) consisted of the following (in thousands):
December 31, 2014 | December 31, 2013 | |||||||
RBL Revolver |
$ | 655,000 | $ | 304,000 | ||||
Second Lien Term Loan |
1,000,000 | 1,000,000 | ||||||
9.75% Senior Notes |
2,250,000 | 2,250,000 | ||||||
|
|
|
|
|||||
Total |
3,905,000 | 3,554,000 | ||||||
Less: debt classified as current |
(3,905,000 | ) | | |||||
|
|
|
|
|||||
Total long-term debt |
$ | | $ | 3,554,000 | ||||
|
|
|
|
F-23
RBL Revolver
Samson Investment Company, a subsidiary of Samson, has a credit agreement providing for a reserve-based revolving credit facility (the RBL Revolver) with JPMorgan Chase Bank, N.A., as the administrative agent, and the other agents and lenders party thereto. The RBL Revolver matures on December 21, 2016 and provides for revolving loans, swingline loans and letters of credit. Outstanding borrowings under the RBL Revolver bear interest at a rate of the London Interbank Offered Rate (LIBOR) plus a LIBOR loan margin of 2.00% and interest is paid monthly. Our borrowing base under the RBL Revolver is based upon our estimated proved reserves and is redetermined semi-annually by our lenders. In addition, the borrowing base may be adjusted pursuant to certain non-scheduled redeterminations, including in connection with certain dispositions of our proved reserves.
In May 2014, we amended the credit agreement governing the RBL Revolver to, among other things:
| modify the financial performance covenant to provide that we shall maintain a ratio of consolidated total first lien debt to consolidated EBITDA (each as defined in the credit agreement, with consolidated EBITDA measured on a rolling four-quarter basis) of not more than 1.5 to 1 as of the end of each fiscal quarter beginning with the first quarter of 2014 and terminating at the end of 2015; and beginning with the first quarter of 2016, a ratio of consolidated total debt to consolidated EBITDA (each as defined in the credit agreement, with consolidated EBITDA measured on a rolling four-quarter basis) of not more than 4.5 to 1 as of the end of each fiscal quarter; |
| reduce the borrowing base from approximately $1.8 billion to $1.0 billion; and |
| permit us to incur an additional $500.0 million of second lien debt without a reduction to the borrowing base, subject to certain limitations and conditions. |
On March 18 2015, we further amended the credit agreement governing the RBL Revolver to, among other things:
| reduce the borrowing base from $1.0 billion to $950.0 million which resulted in a payment of $46.0 million to reduce the amount outstanding on our RBL Revolver; |
| modify the financial performance covenant to provide that we shall maintain a ratio of consolidated total first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 (up from 1.5 to 1.0 previously) as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015, at which point the first lien debt to consolidated EBITDA ratio reverts back to 1.5 to 1 at the end of the fourth quarter of 2015 and beginning with the first quarter of 2016, the credit agreement requires us to maintain a total debt to consolidated EBITDA ratio of not more than 4.5 to 1 as of the end of each fiscal quarter; |
| require minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the second lien term loan credit facility entered into by our subsidiary, Samson Investment Company; |
| increase the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of the companys and its restricted subsidiaries proved reserves; |
| require an automatic reduction in the borrowing base if we receive proceeds related to certain asset dispositions or early settlement of certain derivative financial instruments in the amount of such net proceeds; and |
| increase the interest rates on outstanding borrowings by 0.5%. |
At December 31, 2014, we had approximately $343.4 million of available borrowing capacity under the RBL Revolver after giving effect to outstanding letters of credit. On March 18, 2015, our borrowings outstanding under the RBL Revolver were $947.0 million, excluding outstanding letters of credit, after making a repayment
F-24
of $46.0 million, and we had no available borrowing capacity. During the year ended December 31, 2014, the weighted average interest rate for borrowings under the RBL Revolver was 2.1%.
Senior Notes
On February 8, 2012, our subsidiary, Samson Investment Company, issued 9.75% Senior Notes due in 2020 (the Senior Notes) in the aggregate principal amount of $2.25 billion. The proceeds from the Senior Notes, together with cash on hand, were used to repay, in full, the outstanding borrowings under our senior unsecured bridge facility, plus any accrued and unpaid interest, and to pay related fees and expenses. Interest on the Senior Notes is payable semi-annually in February and August.
In connection with the issuance of the Senior Notes, we entered into a registration rights agreement, which included certain provisions requiring that we file a registration statement to exchange the Senior Notes for new registered notes within a prescribed time period. For the year ended December 31, 2014, our weighted average effective interest rate incurred on our Senior Notes was 10.4%, including additional interest as a result of the registration rights agreement. On August 25, 2014, we completed the exchange offer with respect to the Senior Notes. Consequently, additional interest ceased to accrue on the Senior Notes at that time.
Second Lien Term Loan
In September 2012, our subsidiary, Samson Investment Company, entered into a credit agreement providing for a $1.0 billion second lien term loan credit facility (the Second Lien Term Loan), with Bank of America, N.A., as administrative agent, and the other agents and lenders party thereto. We used approximately $853.0 million of the proceeds of our borrowing under the Second Lien Term Loan to pay down amounts outstanding under the RBL Revolver, with the balance of the proceeds used to pay expenses associated with the financing and for general corporate purposes. The Second Lien Term Loan matures on September 25, 2018.
In December 2013, we amended the credit agreement governing the Second Lien Term Loan to, among other things, effect a refinancing transaction of the Second Lien Term Loan. As a result of this amendment, borrowings outstanding under the Second Lien Term Loan bear interest, at our option, at a rate equal to (i) the then-current LIBOR for the applicable interest period, subject to a 1.00% floor, plus an applicable margin of 4.00% or (ii) an alternative base rate, subject to a 2.00% floor, plus an applicable margin of 3.00%. Prior to the amendment, LIBOR and alternative base rate borrowings were subject to a floor of 1.25% and 2.25%, respectively, and an applicable margin of 4.75% and 3.75%, respectively. For the year ended December 31, 2014, the weighted average interest rate for the amounts outstanding under the Second Lien Term Loan was 5.1%.
Maturities of Long-Term Debt
Contractual maturities of long-term debt outstanding at December 31, 2014 are as follows (in thousands):
2015 |
$ | | ||
2016 |
655,000 | |||
2017 |
| |||
2018 |
1,000,000 | |||
2019 |
| |||
Thereafter |
2,250,000 | |||
|
|
|||
$ | 3,905,000 | |||
|
|
Our debt is reflected as a current liability in our consolidated balance sheet at December 31, 2014 due to uncertainty regarding our ability to comply with certain restrictive covenants contained in our credit facilities. See Note 1 for further information.
F-25
Debt Covenants
As described above, the financial performance covenant in the credit agreement governing the RBL Revolver requires us to operate within established financial ratios. In addition, the March 2015 amendment to the credit agreement governing the RBL Revolver requires us to maintain a certain liquidity on the date of certain interest payments made subsequent to July 1, 2015. Our ability to comply with these covenants depends upon our performance and indebtedness, each of which is impacted by numerous factors, including some that are outside of our control. Accordingly, forecasting our compliance with the financial performance and liquidity covenants in future periods is inherently uncertain. Factors that could impact our future compliance with the financial performance and liquidity covenants include future realized prices for sales of oil, natural gas and natural gas liquids, future production, returns generated by our capital program, future interest costs, future operating costs, future asset sales and future acquisitions, among others.
The credit agreements governing the RBL Revolver and our second lien term loan credit facility and the indenture governing the Senior Notes (collectively, the Debt Agreements) all contain additional customary non-financial covenants that, among other things, restrict our ability to pay dividends, sell assets, make acquisitions or investments, and incur additional indebtedness. In addition, the Debt Agreements contain reporting and administrative requirements, including, but not limited to, the form and content of the auditors report, providing financial statements, compliance certificates and other documents to our counterparties to the Debt Agreements under prescribed timelines.
Subject to any cure periods, the consequences of non-compliance with our debt covenants generally include, but are not limited to, the ability of our counterparties to the Debt Agreements to accelerate our obligation to repay amounts outstanding under our Debt Agreements.
Guarantees and Security
The Senior Notes and the obligations under the RBL Revolver and Second Lien Term Loan credit agreements are guaranteed by Samson Resources Corporation and certain of our subsidiaries. In addition, the obligations under the RBL Revolver and Second Lien Term Loan credit agreements are secured by (i) the pledge of capital stock of Samson Investment Company and the subsidiary guarantors, (ii) real property mortgages on a substantial portion of our oil and gas properties and (iii) security interests in substantially all of our other tangible and intangible assets, except with respect to Samson Resources Corporation whose guarantee is secured solely by the pledge of stock of Samson Investment Company.
Debt Issuance Costs
Costs incurred to obtain debt financing were capitalized as deferred costs and are being amortized over the life of the related debt. The unamortized amounts of debt related costs capitalized at December 31, 2014 and December 31, 2013 are $100.7 million and $125.8 million, respectively, and are included in deferred charges in the consolidated balance sheets.
Future amortization of these costs as of December 31, 2014 is as follows (in thousands):
2015 |
$ | 27,339 | ||
2016 |
28,124 | |||
2017 |
15,315 | |||
2018 |
15,332 | |||
2019 |
12,860 | |||
Thereafter |
1,703 | |||
|
|
|||
$ | 100,673 | |||
|
|
F-26
Note 11. Redeemable Preferred Stock
In December 2011, the Company issued 180,000 shares of cumulative redeemable preferred stock (the Cumulative Preferred Stock). The Cumulative Preferred Stock accrues distributions quarterly at a specified per annum dividend rate on the initial liquidation preference amount of $1,000 per share, which is subject to adjustment for accrual and accumulation of dividends not paid in cash. Distributions can be in cash or in-kind at the Companys election. The dividend rate was 2% for calendar year 2012, escalating 2% each calendar year until reaching 12%, where it remains until the mandatory redemption date. After the mandatory redemption date, the dividend rate will be 15%. The total amounts attributable to accrued and accumulated unpaid dividends at December 31, 2014 and 2013 were $22.8 million and $10.8 million, respectively.
The Cumulative Preferred Stock is redeemable at the option of the Company at any time at a per share redemption price equal to the liquidation amount of the share plus any accrued and unpaid dividends compounded quarterly to the date of redemption and are mandatorily redeemable on the earliest to occur of July 1, 2022 or the consummation of an initial public equity offering or a change in control.
Note 12. Puttable Common Stock
In the quarter ended June 30, 2012, certain members of management purchased approximately 2,475,000 shares of common stock for total consideration of $12.4 million. The common stock purchased by management contains certain put rights that allow the management purchasers to require the Company to repurchase the common stock at either the current fair value of the common stock or the management purchasers initial cost basis of the stock depending on the circumstances. Additionally, the common stock purchased by management contains certain call rights that allow the Company to repurchase the stock. The proceeds received from the sale of the common stock are presented outside of permanent equity in the consolidated balance sheets.
We repurchased 450,000 and 605,000 shares of our common stock for approximately $2.2 million and $3.0 million during the years ended December 31, 2014 and 2013, respectively. For shares repurchased at an amount less than the original cost, a portion of the original cost reflected outside of permanent equity was reclassified to common stock and additional paid in capital in the consolidated balance sheets.
Note 13. Shareholders Equity
At the formation of Samson, 2,000,000,000 shares of common stock were authorized to be issued. On December 21, 2011, 829,000,000 shares of Samsons common stock were sold for total consideration of $4.1 billion. Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of common stock will be entitled to dividends in such amounts and at such times as our Board of Directors, in its discretion, may declare out of funds legally available for the payment of dividends. No dividends have been declared or paid through December 31, 2014. No shares of common stock have preemptive rights to purchase additional shares of our common stock or other securities. The number of authorized shares of common stock available for future issuance is reduced by the number of outstanding shares of common stock and the number of outstanding shares of puttable common stock.
Note 14. Stock Compensation
2011 Stock Incentive Plan
On April 16, 2012, we implemented the Samson Resources Corporation 2011 Stock Incentive Plan (the 2011 Plan). The 2011 Plan authorizes the grant of awards in the form of restricted shares, phantom stock, warrants or other securities that are convertible or exercisable into shares of common stock. Employees, members of the Board of Directors, consultants and service providers of Samson are eligible to receive awards under the 2011 Plan. In the second quarter of 2013, we amended the 2011 Plan to increase the total number of securities available to be granted from 10% of the common stock on a fully diluted basis to 98,200,000 securities.
F-27
Stock Options
The following table provides information about our stock option activity under the 2011 Plan for the following years:
Number of Stock Options |
Range of Exercise Prices |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Life (years) |
|||||||||||
Outstanding at December 31, 2011 |
| $ | | | ||||||||||
Options granted |
61,642,700 | $5.00 | 5.00 | |||||||||||
Options forfeited |
(14,965,950 | ) | $5.00 | 5.00 | ||||||||||
|
|
|||||||||||||
Outstanding at December 31, 2012 |
46,676,750 | $5.00 | $ | 5.00 | 9.3 | |||||||||
|
|
|||||||||||||
Options granted |
50,049,800 | $4.00 - $7.50 | 5.41 | |||||||||||
Options forfeited |
(10,028,950 | ) | $4.00 - $5.00 | 4.70 | ||||||||||
Options expired |
(6,827,950 | ) | $5.00 | 5.00 | ||||||||||
|
|
|||||||||||||
Outstanding at December 31, 2013 |
79,869,650 | $4.00 - $7.50 | $ | 5.29 | 9.0 | |||||||||
|
|
|||||||||||||
Options granted |
3,675,600 | $2.50 | 2.50 | |||||||||||
Options forfeited |
(5,668,420 | ) | $2.50 - $5.00 | 3.07 | ||||||||||
Options expired |
(3,815,930 | ) | $2.50 - $5.00 | 3.12 | ||||||||||
|
|
|||||||||||||
Outstanding at December 31, 2014 |
74,060,900 | $2.50 - $7.50 | $ | 3.41 | 8.1 | |||||||||
|
|
|||||||||||||
Vested at December 31, 2014 |
40,462,400 | $2.50 - $7.50 | $ | 3.37 | 7.6 | |||||||||
|
|
|||||||||||||
Exercisable at December 31, 2014 |
29,053,670 | $2.50 - $7.50 | $ | 3.08 | 7.7 | |||||||||
|
|
Stock options are valued at the date of award and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The following table summarizes information about stock based compensation related to stock options for the periods presented (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Grant date fair value for stock options granted during the period |
$ | 22,319 | $ | 68,673 | $ | 148,250 | ||||||
|
|
|
|
|
|
|||||||
Stock based compensation related to stock options: |
||||||||||||
Expensed during the period |
$ | 34,047 | $ | 26,728 | $ | 35,606 | ||||||
Capitalized during the period |
5,371 | 4,382 | 3,882 | |||||||||
|
|
|
|
|
|
|||||||
Total stock based compensation related to stock options during the period |
$ | 39,418 | $ | 31,110 | $ | 39,488 | ||||||
|
|
|
|
|
|
|||||||
Income tax benefit related to stock options |
$ | 14,081 | $ | 11,169 | $ | 12,464 | ||||||
|
|
|
|
|
|
F-28
We estimated the fair value of each grant using the Black-Scholes-Merton option pricing model. Assumptions utilized in the model are shown below:
Awards issued in 2014 |
Awards issued in 2013 |
Awards issued in 2012 | ||||
Risk-free interest rate |
1.98 - 2.20% | 1.35 - 2.25% | 0.86 - 1.14% | |||
Expected term (years) |
7.25 | 7.25 | 6.25 | |||
Expected volatility |
49.70 - 49.86% | 47.91 - 49.40% | 49.30% | |||
Weighted average volatility |
49.79% | 49.22% | 49.30% | |||
Expected dividend yield |
| | |
The risk-free interest rate is based on U.S. Treasury zero-coupon security issuances with remaining terms equal to the expected term. The expected term of the options is based on vesting schedules, consideration of contractual terms and expectations of future employee behaviors. Expected volatilities are based on a combination of historical and implied volatilities of comparable companies. The forfeiture rate for stock options issued under the 2011 Plan to non-officer employees is 16%. We assumed no future forfeitures of stock options issued to our officers.
As of December 31, 2014 unrecognized stock-based compensation cost (either expensed or capitalized) related to nonvested stock option awards was $66.8 million. The unrecognized cost is expected to be recognized over a weighted average period of two years.
Stock Option Modifications
Modifications to our outstanding stock options result in additional compensation cost if the fair value of the modified award immediately after the modification exceeds the fair value of the outstanding award immediately before the modification. For vested awards, the modification results in immediate expense recognition. For unvested awards, the additional compensation cost is recognized over the remaining requisite service period. During the first quarter of 2014, we modified the terms of certain stock options issued under the 2011 Plan. The exercise price for all non-officer employee held stock options was changed to $2.50 from the original $5.00 or $4.00 exercise prices. In addition, modifications were made to certain stock options held by the officers of the Company, which also included reductions in the number of stock options held by our Chief Executive Officer and decreases to the exercise prices of certain stock options held by all officers. After the modifications, the exercise prices for a majority of our outstanding stock options was $2.50 while a portion of our stock options held by our Chief Executive Officer had exercise prices of $4.00, $5.00, and $7.50. The modification of the exercise price of certain options increased stock compensation expense by $10.7 million after the effects of capitalization for the year ended December 31, 2014.
Restricted Stock
Grants of 10,000,000 shares and 6,800,000 shares of restricted stock were made to certain officers during the years ended December 31, 2014 and December 31, 2013, respectively. The original vesting periods for shares of restricted stock granted in 2014 and 2013 were five and three years, respectively, prior to the approval of the officer retention letter agreements, which are described below.
F-29
The following table provides information about our restricted stock activity under the 2011 Plan for the years ended December 31, 2014 and 2013:
Number of Shares |
Weighted Average Grant Date Fair Value per Share |
|||||||
Outstanding at December 31, 2012 |
| $ | | |||||
Stock granted |
6,800,000 | 3.36 | ||||||
Stock vested |
| | ||||||
Stock forfeited |
(400,000 | ) | 3.40 | |||||
|
|
|
|
|||||
Shares outstanding at December 31, 2013 |
6,400,000 | $ | 3.36 | |||||
Stock granted |
10,000,000 | 2.10 | ||||||
Stock vested |
| | ||||||
Stock forfeited |
| | ||||||
|
|
|
|
|||||
Shares outstanding at December 31, 2014 |
16,400,000 | $ | 2.59 | |||||
|
|
|
|
|||||
Vested at December 31, 2014 |
| | ||||||
|
|
|
|
Compensation expense related to our restricted stock is valued at the date of award based on the estimated fair value of an unrestricted share (which includes a lack of marketability discount of 15%). Compensation cost is recognized on a straight-line basis over the requisite service period. We assume no future forfeitures of restricted stock issued to our officers. The following table summarizes information about stock based compensation related to restricted stock for the periods presented (in thousands):
Year Ended December 31, | ||||||||
2014 | 2013 | |||||||
Grant date fair value for restricted stock granted during the period |
$ | 21,027 | $ | 22,865 | ||||
|
|
|
|
|||||
Stock based compensation related to restricted stock: |
||||||||
Expensed during the period |
$ | 16,496 | $ | 2,545 | ||||
Capitalized during the period |
39 | | ||||||
|
|
|
|
|||||
Total stock based compensation related to restricted stock during the period |
$ | 16,535 | $ | 2,545 | ||||
|
|
|
|
|||||
Income tax benefit related to restricted stock |
$ | 5,906 | $ | 914 | ||||
|
|
|
|
As of December 31, 2014 unrecognized stock-based compensation cost (either expensed or capitalized) related to unvested restricted stock awards was $23.5 million. The unrecognized stock-based compensation expense will be recognized through September 1, 2015.
Officer Retention Agreements and Officer Voluntary Severance Plan
During the year ended December 31, 2014, the Compensation Committee of the Board of Directors approved officer retention letter agreements and adopted the Samson Resources Corporation Voluntary Severance Plan for Officers (the Officer Voluntary Severance Plan). Pursuant to the terms of these arrangements, officers that remained employed by the Company (Remaining Officers) through September 1, 2015 (the Retention Date) and continued their employment after such date were entitled to receive (i) a grant of shares of vested restricted stock in an amount equal to two times the sum of such officers annual base salary and target bonus amount (the Retention Amount), (ii) the accelerated vesting of all unvested equity awards held by such officer as of November 14, 2014, with vesting occurring as of the Retention Date (the Accelerated Vesting Benefit), and (iii) special temporary put and call rights for all vested equity awards held by such officer that were exercisable over a specified period following the Retention Date and would allow for repurchase based on
F-30
the fair market value of the Companys common stock as of the Retention Date (the Temporary Put and Call Rights). Subject to certain conditions, Remaining Officers that voluntarily terminated their employment as of the Retention Date would have been entitled to receive (i) the payment of the Retention Amount in cash over a specified period, (ii) the Accelerated Vesting Benefit, (iii) certain severance-related benefits, including a pro-rated portion of the 2015 target bonus and other customary benefits, and (iv) the Temporary Put and Call Rights. Officers that were terminated by the Company other than for cause on or prior to the Retention Date were entitled to receive payments and benefits substantially similar to those described above. The Accelerated Vesting Benefit increased compensation expense in 2014 and 2015 but does not change the total estimated compensation expense to be recognized for previously granted awards.
As provided for in the retention letter agreements described above, the March 2015 workforce reduction (described in Note 15) triggered severance benefits to be paid to certain officers. The terminated officers signed customary release agreements which included the forfeiture of all vested and unvested equity awards.
In March 2015, agreements were executed with each remaining officer (collectively, the March 2015 Officer Agreements) which had the effect of canceling the provisions in the retention letter agreements providing for the granting of vested restricted stock and the establishment of the Temporary Put and Call Rights and canceling the Officer Voluntary Severance Plan. In exchange for relinquishing the majority of benefits previously provided for in the retention letter agreements and Officer Voluntary Severance Plan, the remaining officers will receive payments in the second quarter of 2015 equal to one-half of the Retention Amount provided in the retention letter agreements conditioned upon the officer continuing employment with the Company through September 1, 2015, unless the officer is terminated by the Company other than for cause. In addition, the March 2015 Officer Agreements provided for quarterly incentive payments through the third quarter of 2015.
We estimate that the total payments to remaining officers pursuant to the provisions of the March 2015 Officer Agreements will be significant. The liability recorded associated with the various components of the officer retention agreements, the Officer Voluntary Severance Plan, and the March 2015 Officer Agreements is included in accrued and other current liabilities in the Companys consolidated balance sheet.
Cash Incentive Awards
During the year ended December 31, 2014, the Compensation Committee of the Board of Directors approved providing cash based incentive awards for certain non-officer employees. A portion of the awards outstanding at September 30, 2014 were originally issued with a vesting date of April 1, 2017. During the quarter ended September 30, 2014, the Compensation Committee of the Board of Directors approved modifying the vesting provisions of certain awards so that payment of all outstanding cash based incentive awards is September 1, 2015 (or if earlier, the date of the employees termination by the Company other than for cause). The liability recorded associated with cash incentive awards is included in accrued and other current liabilities in the Companys consolidated balance sheet. In March 2015, the cash incentive awards were modified so that vesting will be on an accelerated basis beginning in the first quarter of 2015 through the third quarter of 2015. Half of the expected payments are forfeitable if the recipient voluntarily leaves the Company prior to September 1, 2015.
Consultant Plan
In addition to the stock options issued under the 2011 Plan, we have also issued 1,200,000 options under a separate plan (the Consultant Plan) established to provide stock options to consultants for services rendered in connection with the Acquisition. At December 31, 2014, 881,250 options, with an exercise price of $5.00, were exercisable and no additional options were available for future issuance under the Consultant Plan.
Note 15. Restructuring
In December 2012, we initiated a restructuring plan (the Restructuring Plan) to reduce operating costs and improve profitability. Under the Restructuring Plan, we closed our Midland, Texas office and implemented a
F-31
reduction in force of approximately 120 employees across multiple functions throughout the Company. We incurred expenses of approximately $46.6 million in restructuring charges for the year ended December 31, 2012.
In February 2013, we announced that we had completed the Restructuring Plan. As of December 31, 2013 or 2014, no liability was recorded in our consolidated balance sheet related to the restructuring.
In March 2015, we announced a reduction in our workforce of approximately 30% in connection with a corporate restructuring. As a result of the workforce reduction, we expect to incur restructuring charges in excess of $30.0 million, which will primarily relate to severance payments to terminated employees and officers.
Note 16. Supplemental Information to Statement of Cash Flows
The following table summarizes interest and income taxes paid for the periods presented (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Interest paid (net of capitalized interest of $243,110, $341,719 and $279,659, respectively) |
$ | 58,436 | $ | | $ | | ||||||
Income taxes paid, net |
$ | 75 | $ | 243 | $ | (2,937 | ) |
Supplemental Non-Cash Investing and Financing Activities
Total payables included in accrued liabilities related to acquisition and drilling expenditures for oil and gas properties for the Company were $82.5 million, $77.0 million and $143.4 million at December 31, 2014, 2013 and 2012, respectively. Non-cash investing activities associated primarily with tubular oil and gas equipment were approximately $10.3 million, $44.2 million and $15.1 million for the years ended December 31, 2014, 2013 and 2012, respectively
Note 17. Employee Benefits
Employee Benefit Programs
We have an employee healthcare plan which provides health and death benefits to substantially all employees. Death benefits are provided by an employer-funded policy held with an insurance company. The Companys contributions charged to expense for the years ended December 31, 2014, 2013 and 2012 were $10.6 million, $10.5 million, and $11.2 million, respectively.
401(k) Plan
We have a voluntary defined contribution plan, which becomes effective for all new, regular full-time employees upon the first day of employment, as defined in the plan document. Participants may make voluntary contributions to the plan from 1% to 100% of their monthly compensation up to IRS limitations. We make matching contributions equal to the participants first 6% in contributions and an additional 2% non-matching contribution. Employer contributions were $8.6 million, $7.3 million, and $8.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Note 18. Commitments and Contingencies
Commitments
Operating Leases
We lease corporate office space in Tulsa, Oklahoma, Houston, Texas and Denver, Colorado, as well as a number of other field office locations. The Company recorded rental expense of approximately $6.3 million,
F-32
$5.9 million, and $5.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. Rental expense is included in general and administrative expenses in the consolidated statements of loss and comprehensive loss.
Future minimum annual payments under non-cancelable operating leases as of December 31, 2014, are as follows (in thousands):
2015 |
$ | 7,032 | ||
2016 |
6,835 | |||
2017 |
6,827 | |||
2018 |
6,348 | |||
2019 |
6,491 | |||
Thereafter |
25,141 | |||
|
|
|||
$ | 58,674 | |||
|
|
Other Commercial Commitments
We have commitments for drilling rigs with payments under the contracts accounted for as capital additions to our oil and gas properties. As of December 31, 2014, future payments under these agreements were approximately $12.5 million for 2015. Subsequent to December 31, 2014, we terminated approximately $12.5 million of these drilling rig commitments and incurred rig termination fees of approximately $5.2 million as a result.
For the next twelve months, we have non-cancelable commitments to purchase approximately $7.6 million of new tubular and related equipment, including inspection and transportation costs, for drilling and completion projects.
Letters of Credit and Bonds
As of December 31, 2014, we had outstanding irrevocable letters of credit totaling approximately $1.6 million to guarantee payment of certain drilling and workers compensation insurance obligations. Additionally, at December 31, 2014, we had approximately $14.1 million in outstanding bonds securing various commitments, such as plugging costs and surface damages.
Gathering and Transportation Agreements
We have contractual commitments with midstream service companies and pipeline carriers for future gathering and transportation of our production to market.
Net aggregate undiscounted commitments under our gathering and transportation agreements at December 31, 2014 are presented below (in thousands):
2015 |
$ | 7,074 | ||
2016 |
7,482 | |||
2017 |
12,364 | |||
2018 |
12,525 | |||
2019 |
11,551 | |||
Thereafter |
35,834 | |||
|
|
|||
$ | 86,830 | |||
|
|
F-33
Change of Control Agreements
Effective January 1, 2014, the Company adopted a Change in Control Severance Plan for non-officer employees that applies to eligible employees and a Change in Control Severance Plan for officers (collectively, the Change in Control Severance Plans) that applies to all officers except the Chief Executive Officer, who is covered by an employment agreement. The Change in Control Severance Plans provide for the payment of cash compensation and certain other benefits to eligible officers and non-officer employees in the event of a change in control and a qualifying termination of employment. The obligations under the Change in Control Severance Plans are generally based on the terminated employees cash compensation, employment tenure, and position within the Company. Depending on the facts and circumstances associated with a potential change in control, the total payments made pursuant to the Change in Control Severance Plans or employment agreements could be material. No liability has been recorded at December 31, 2014 associated with the Change in Control Severance Plans.
We had Change of Control Agreements (CC Agreements) with a large portion of our employees through December 2013. Severance benefits payable are recorded when it is probable that the obligation has been incurred and the amount can be reasonably estimated. In December 2012, $46.6 million of restructuring charges were recognized under our CC Agreements in conjunction with our restructuring. The restructuring is further described in Note 15. In addition, approximately $9.4 million in severance related costs were incurred during the year ended December 31, 2013 due to the departure of certain members of our management team. The 2013 severance costs were recorded as lease operating and general and administrative expense in our consolidated statement of loss and comprehensive loss.
Employee Severance Plan
Effective September 1, 2014, the Company adopted the Samson Resources Corporation Job Elimination Severance Plan for Non-Officers (the Employee Severance Plan) that applies to all eligible full-time non-officer employees. The Employee Severance Plan generally provides for severance payments to such employees if employment is involuntarily terminated in connection with a corporate restructuring, downsizing, reduction in force, asset sales, or similar reason through September 1, 2015. Depending on future facts and circumstances, total payments made pursuant to the Employee Severance Plan could be material. No liability has been recorded at December 31, 2014 associated with the Employee Severance Plan. In March 2015, we announced reduction in workforce of 30% of employees in connection with a corporate restructuring. As a result of the workforce reduction, we expect to pay in excess of $30.0 million of severance payments to terminated employees and officers under the Employee Severance Plan in addition to other accrued compensation and benefits.
The employment agreement with our Chief Executive Officer provides for the payment of cash compensation and certain other benefits in the event of a severance or change in control depending upon the circumstances, which could be material.
Litigation and Contingencies
We are involved in various matters incidental to our operations and business that might give rise to a loss contingency, including, among other things, legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental or other matters. In addition, we are subject, from time to time, to customary audits and investigations by governmental and tribal authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as our compliance with unclaimed property (escheatment) requirements and other laws. Unclaimed property laws generally require us to turn over to certain governmental authorities the property of others held by us that has been unclaimed for a specified period of time. In addition, other parties with an interest in wells operated by us have the ability under various contractual agreements to perform audits of our joint interest billing practices where we receive reimbursements from these owners for their share of the costs incurred in connection with the oil and gas properties that we operate.
F-34
We vigorously defend ourselves in these matters, including through the retention of outside counsel where appropriate. A loss contingency may take the form of (i) overtly threatened or pending litigation, (ii) a contractually assumed obligation, or (iii) an unasserted possible claim or assessment. For these matters, we review the merits of the asserted claims, consult with internal and outside counsel as appropriate, assess the degree of probability of an unfavorable outcome, consider possible legal, administrative, litigation, and resolution or settlement strategies, and the availability of insurance coverage, subrogation, indemnities and potential third party liabilities.
If we determine that an unfavorable outcome or loss of a particular matter is probable and the amount of the loss can be reasonably estimated, we accrue a liability for the contingent obligation, as well as any expected insurance recovery amounts up to the accrued loss. Recovery of any amount in excess of the related recorded contingent loss is recognized if and when all contingencies related to the recovery have been resolved, which generally corresponds with the receipt of cash in excess of the related recorded contingent loss. As new information becomes available as a result of activities in such matters, legal or administrative rulings in similar matters or a change in applicable law, our conclusions regarding the probability of outcomes and estimated loss may change. The impact of subsequent changes to our accruals may have a material effect on our results of operations reported in a single period. We expense all legal fees in the period the expenses are incurred.
In matters where litigation is pending, it is common and often required for the parties to attend non-binding mediations or settlement conferences. Such mediations or conferences can end in settlement of litigation matters. We participated in such non-binding mediation and subsequent discussions in an action seeking class certification and damages related to royalty payments for wells located in Oklahoma. In December 2013, a settlement with the plaintiffs was approved by the court. At December 31, 2013, an accrual for this matter was recorded in our consolidated balance sheet. Settlement payments totaling $15.2 million were made in the first quarter of 2014.
In 2014, in connection with an ongoing audit on behalf of a federal regulator, we began reviewing the manner in which our obligations to make royalty payments for natural gas production on federal leases should be determined. The review involves attempting to determine components of certain fees we pay to transport and process some of our natural gas production associated with individual federal leases and evaluate how each component impacts our royalty payment obligations. We estimate that this review will result in additional royalty payments made related to natural gas production on certain federal leases and have recorded a liability associated with this matter. Estimating the liability is inherently uncertain as each contract associated with individual federal leases has to be analyzed and the estimated fee components will ultimately be subject to approval by the federal regulator. Consequently, it is reasonably possible that a loss exceeding the liability recorded has been incurred and we cannot estimate the range of loss in excess of our recorded liability. However, we do not currently expect our payment of additional royalties will be materially in excess of the liability recorded.
Also in 2014, an audit of our unclaimed property practices in certain states was commenced and we entered into a Voluntary Disclosure Agreement (VDA) with the state of Oklahoma related to our unclaimed property reporting practices. The unclaimed property audit and VDA process is ongoing and we expect resolution of both processes to occur in 2015.
As of December 31, 2014, our total accrual for all loss contingencies was $12.2 million, of which $3.7 million was included in oil and natural gas revenues held for distribution and $8.5 million was included in accrued and other current liabilities in our consolidated balance sheet. Because of the uncertainty inherent in estimating probable payments associated with loss contingencies, it is reasonably possible that our accrual will change as facts and circumstances change and any such changes may be material.
F-35
Note 19. Income Taxes
Samson is subject to corporate income taxes. Income tax benefit for the periods presented consisted of the following (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Current taxes: |
||||||||||||
Federal |
$ | | $ | | $ | | ||||||
Foreign |
| | 58 | |||||||||
State |
264 | 453 | | |||||||||
Deferred taxes: |
||||||||||||
Federal |
(772,858 | ) | (600,428 | ) | (817,043 | ) | ||||||
State |
(16,925 | ) | (13,983 | ) | 11,067 | |||||||
|
|
|
|
|
|
|||||||
Income tax benefit |
$ | (789,519 | ) | $ | (613,958 | ) | $ | (805,918 | ) | |||
|
|
|
|
|
|
Total income tax benefit differed from the amounts computed by applying the U.S. federal income tax rate to net loss from continuing operations before income taxes as a result of the following:
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
U.S. statutory rate |
35 | % | 35 | % | 35 | % | ||||||
State taxes |
1 | % | 1 | % | 0 | % | ||||||
Other |
0 | % | 0 | % | 0 | % | ||||||
|
|
|
|
|
|
|||||||
36 | % | 36 | % | 35 | % | |||||||
|
|
|
|
|
|
The tax effects of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts and the tax credits and other items that give rise to the deferred tax assets and deferred tax liabilities are as follows (in thousands):
December 31, 2014 | December 31, 2013 | |||||||
Deferred tax liabilities: |
||||||||
Oil and gas properties |
$ | (1,324,142 | ) | $ | (2,003,119 | ) | ||
Other property and equipment |
(86,411 | ) | (116,691 | ) | ||||
Unrealized gains on commodity hedges |
(54,077 | ) | | |||||
|
|
|
|
|||||
Total deferred tax liabilities |
$ | (1,464,630 | ) | $ | (2,119,810 | ) | ||
|
|
|
|
|||||
Deferred tax assets: |
||||||||
Stock compensation |
$ | 44,093 | $ | | ||||
Asset retirement obligation |
26,991 | 21,571 | ||||||
Unrealized losses on commodity hedges |
| 15,851 | ||||||
Capitalized transaction costs |
33,745 | 35,142 | ||||||
Net operating loss |
515,320 | 461,701 | ||||||
Gas balancing obligation |
5,329 | 5,454 | ||||||
Accrued liabilities |
59,402 | 34,232 | ||||||
Other |
14,413 | 15,036 | ||||||
|
|
|
|
|||||
Total deferred tax assets |
$ | 699,293 | $ | 588,987 | ||||
|
|
|
|
|||||
Net deferred tax liabilities |
$ | (765,337 | ) | $ | (1,530,823 | ) | ||
|
|
|
|
Samson has net operating loss carryforwards of approximately $1.5 billion available to offset future income taxes which expire between 2015 and 2034. These carryforwards
F-36
are primarily related to expensing intangible drilling costs and accelerated depreciation deductions. We have not recorded a valuation allowance associated with our deferred tax assets as we believe it is more likely than not that the assets will be realized. Our expectations are based upon current estimates of taxable income during future periods, considering limitations on utilization of these benefits as set forth by tax regulations and based on the reversing effects of our deferred tax liabilities. Significant changes in our estimates caused by variables such as future oil, gas and natural gas liquids prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Samson will generate any specific level of continuing taxable earnings.
Samsons primary deferred tax liability is due to the fact that the book value of its oil and gas assets exceeds its tax basis in those assets. At December 31, 2014, the tax basis in Samsons oil and gas assets was $1.2 billion.
We evaluated our tax positions and concluded that we have not taken any uncertain tax positions that require an adjustment to the financial statements. Tax penalties and related interest would be charged to the provision for income taxes when uncertain tax positions are recorded in the financial statements. Therefore, there are no related accruals for interest and penalties related to unrecognized tax benefits at December 31, 2014.
Note 20. Related Party Transactions
We have a consulting agreement with affiliates of KKR, our principal shareholder, and other initial equity investors pursuant to which we receive management services and incur a quarterly management fee. At the commencement of the agreement in 2012, the aggregate annual fee was $20.0 million, resulting in quarterly payments of $5.0 million. As required by the agreement, the aggregate annual fee and corresponding quarterly payments increases 5.0% each year. We incurred $22.1 million, $21.0 million and $20.0 million in the years ended December 31, 2014, 2013 and 2012, respectively. This fee is included in the consolidated statements of loss and comprehensive loss as related party management fee. The consulting agreement providing for the related party management fee, which has a ten year term, will also terminate (i) automatically immediately following the consummation of an initial public offering (unless we elect to continue the agreement) and (ii) at our election, in connection with certain sales of shares of our common stock held by our principal stockholders. If the consulting agreement is terminated under such circumstances, then we must pay a termination fee based on the net present value of future payment obligations under the consulting agreement. In March 2015, the shareholders consented to the extension of time for the payment of the quarterly management fee until such time as the shareholders determine to reinstate such payment. The extension does not change the amount of management fee incurred pursuant to the consulting agreement.
Effective February 10, 2012, we entered into a Gas Offtake Rights Agreement (the Offtake Agreement) with Trademark Merchant Energy, LLC (TME) granting TME the right to acquire a percentage of the natural gas delivered to specified delivery points at an adjusted index price. ITOCHU Corporation (ITOCHU), a minority owner of Samsons common stock, controls TME and is party to the Offtake Agreement. During 2013, the Offtake Agreement was assigned to another affiliate of ITOCHU. Total gross receipts under the Offtake Agreement were approximately $2.1 million, $59.4 million and $43.0 million for the years ended December 31, 2014, 2013 and 2012, respectively.
KKR Capstone Consulting, LLC (Capstone) is a consulting company of operational professionals that works exclusively with KKRs portfolio company management teams. During the years ended December 31, 2014, 2013 and 2012, we paid approximately $0.5 million, $1.9 million and $0.5 million, respectively, to Capstone for consulting services it provided to us.
We also, from time to time, purchase pipe and pumping supplies from Bell Supply Company LLC, which is an affiliate of Crestview Partners II GP, L.P. One of our directors serves on the board of directors of the parent to Bell Supply Company LLC. For the years ended December 31, 2014, 2013 and 2012, we paid approximately $2.1 million, $2.6 million and $2.0. million, respectively, for supplies from Bell Supply Company LLC.
F-37
Since 2009, we have, from time to time, engaged the services of Alliant Insurance Services, Inc. (Alliant), an insurance brokerage firm. In 2012, one or more affiliates of KKR acquired a controlling ownership interest in Alliant. During the years ended December 31, 2014, 2013 and 2012, we paid $0.3 million in fees for each year to Alliant for insurance brokerage services.
An affiliate of KKR served as joint manager and arranger for the original financing of the Second Lien Term Loan in September 2012 and in the refinancing of the Second Lien Term Loan in December 2013 and also served as an initial purchaser of the Senior Notes in February 2012. The affiliate received customary fees and expenses and for which it is indemnified by us against certain liabilities.
We have, from time to time, engaged Select Energy Services, LLC and its subsidiary, Peak Oilfield Services LLC, for water hauling, tank rental and other well-site water management and equipment rental services. Select Energy Services, LLC is an affiliate of Crestview Partners II GP, L.P. One of our directors is a managing director of the investment manager of the funds affiliated with Crestview Partners II GP, L.P. and serves as a director of Select Energy Services, LLC. We paid approximately $0.7 million, $0.2 million and $0.4 million, respectively, in the aggregate to Select Energy Services, LLC and Peak Oilfield Services LLC for the years ended December 31, 2014, 2013 and 2012, respectively.
In March 2015, we completed the sale of certain of our oil and gas assets to an entity affiliated with Natural Gas Partners in exchange for approximately $48.0 million. Investment funds affiliated with Natural Gas Partners IX, L.P. indirectly own interests in Samson Aggregator.
The Company is party to an agreement with CoreTrust Purchasing Group (CoreTrust), a group purchasing program that maintains relationships with certain vendors, from which participating companies may purchase products or services pursuant to the terms of the purchasing program. Since April 2013, the Company has, from time to time, purchased certain products and services from various vendors through the CoreTrust purchasing program. One or more affiliates of KKR have an indirect ownership interest in CoreTrust.
Note 21. Condensed Consolidating Financial Information
Samson Resources Corporation and specified 100% owned subsidiaries (Geodyne Resources, Inc., Samson Contour Energy Co., Samson Contour Energy E&P, LLC, Samson Holdings, Inc., Samson Lone Star, LLC, Samson Resources Company, and Samson-International, Ltd. (collectively the Subsidiary Guarantors and, together with Samson Resources Corporation, the Guarantors)) of Samson Investment Company (the Issuer), a 100% owned subsidiary of Samson Resources Corporation, fully and unconditionally guarantee obligations under the Senior Notes. These guarantees are joint and several obligations of the Guarantors.
Any guarantee by a Guarantor will be automatically and unconditionally released and discharged upon (1)(A) in the case of any Subsidiary Guarantor, the sale, exchange or transfer of the capital stock of the Subsidiary Guarantor or (B) the sale, exchange or transfer of all, or substantially all, of the assets of such Guarantor, (2) the release or discharge of the guarantee by the Guarantor with respect to the RBL Revolver, (3) in the case of any Subsidiary Guarantor, the designation of it as an Unrestricted Subsidiary in compliance with the indenture, (4) the legal or covenant defeasance or discharge of the indenture or (5) the merger or consolidation of any Guarantor with and into the Issuer or another Guarantor, all in compliance with the provisions of the Senior Notes.
Covenants of the Senior Notes limit the ability of the Issuer and the Subsidiary Guarantors to, among other things:
| incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; |
| pay dividends on or make other distributions in respect of capital stock or make other restricted payments; and |
| enter into certain transactions with affiliates. |
F-38
We have prepared condensed consolidating financial statements in order to quantify assets, results of operations and cash flows of Samson Resources Corporation, the Issuer, the Subsidiary Guarantors and non-guarantor subsidiaries. The following condensed consolidating balance sheets, condensed consolidating statements of income (loss) and comprehensive income (loss) and condensed consolidating statements of cash flows for the periods presented, present financial information for Samson Resources Corporation, as the parent of the Issuer on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Issuer on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Subsidiary Guarantors on a stand-alone basis, the financial information of our non-guarantor subsidiaries on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the financial information on a condensed consolidated basis. As Samson Resources Corporation, the Issuer, the Subsidiary Guarantors and the non-guarantor subsidiaries are separate taxable entities, income taxes are provided with respect to the individual operations of each entity (excluding any equity pick up) only, and deferred income taxes are recorded separately.
F-39
SAMSON RESOURCES CORPORATION
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2014
(In thousands)
Samson Resources Corporation (Parent Guarantor) |
Samson Investment Company (Issuer) |
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Eliminations | Consolidated | |||||||||||||||||||
Cash and cash equivalents |
$ | | $ | 281 | $ | 23,451 | $ | 94 | $ | | $ | 23,826 | ||||||||||||
Accounts receivable, net |
| | 173,524 | | | 173,524 | ||||||||||||||||||
Intercompany receivables |
36,045 | 200,321 | | | (236,366 | ) | | |||||||||||||||||
Other current assets |
| | 139,231 | | | 139,231 | ||||||||||||||||||
Oil and gas properties, net |
| | 4,822,623 | | | 4,822,623 | ||||||||||||||||||
Other property and equipment |
| | 291,761 | | | 291,761 | ||||||||||||||||||
Investment in subsidiaries |
336,358 | 3,802,678 | | | (4,139,036 | ) | | |||||||||||||||||
Other noncurrent assets |
22,930 | 322,231 | 45,696 | 19,557 | (253,067 | ) | 157,347 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total assets |
$ | 395,333 | $ | 4,325,511 | $ | 5,496,286 | $ | 19,651 | $ | (4,628,469 | ) | $ | 5,608,312 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Accounts payable |
$ | | $ | | $ | 19,555 | $ | 536 | $ | | $ | 20,091 | ||||||||||||
Intercompany payables |
| | 218,664 | 17,702 | (236,366 | ) | | |||||||||||||||||
Accrued and other current liabilities |
| 84,153 | 240,442 | 35 | | 324,630 | ||||||||||||||||||
Other current liabilities |
| | 117,156 | | | 117,156 | ||||||||||||||||||
Debt classified as current |
| 3,905,000 | | | | 3,905,000 | ||||||||||||||||||
Deferred income tax liabilities |
| | 999,904 | | (253,067 | ) | 746,837 | |||||||||||||||||
Other noncurrent liabilities |
| | 99,265 | | | 99,265 | ||||||||||||||||||
Cumulative preferred stock subject to mandatory redemption |
202,808 | | | | | 202,808 | ||||||||||||||||||
Puttable common stock |
1,000 | | | | | 1,000 | ||||||||||||||||||
Shareholders equity |
191,525 | 336,358 | 3,801,300 | 1,378 | (4,139,036 | ) | 191,525 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total liabilities and shareholders equity |
$ | 395,333 | $ | 4,325,511 | $ | 5,496,286 | $ | 19,651 | $ | (4,628,469 | ) | $ | 5,608,312 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
F-40
SAMSON RESOURCES CORPORATION
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2013
(In thousands)
Samson Resources Corporation (Parent Guarantor) |
Samson Investment Company (Issuer) |
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Eliminations | Consolidated | |||||||||||||||||||
Cash and cash equivalents |
$ | | $ | 238 | $ | 399 | $ | 90 | $ | | $ | 727 | ||||||||||||
Accounts receivable, net |
10 | | 174,979 | | | 174,989 | ||||||||||||||||||
Intercompany receivables |
| 22,204 | 19,791 | | (41,995 | ) | | |||||||||||||||||
Other current assets |
| 14,392 | 30,192 | 52 | | 44,636 | ||||||||||||||||||
Oil and gas properties, net |
| | 6,738,239 | | | 6,738,239 | ||||||||||||||||||
Other property and equipment |
| | 302,693 | | | 302,693 | ||||||||||||||||||
Investment in subsidiaries |
1,696,448 | 5,051,279 | | | (6,747,727 | ) | | |||||||||||||||||
Other noncurrent assets |
10,569 | 309,373 | 71,296 | 53,230 | (268,066 | ) | 176,402 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total assets |
$ | 1,707,027 | $ | 5,397,486 | $ | 7,337,589 | $ | 53,372 | $ | (7,057,788 | ) | $ | 7,437,686 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Accounts payable |
$ | | $ | | $ | 36,255 | $ | 12 | $ | | $ | 36,267 | ||||||||||||
Intercompany payables |
| | | 41,995 | (41,995 | ) | | |||||||||||||||||
Accrued and other current liabilities |
| 95,268 | 244,046 | 1,920 | | 341,234 | ||||||||||||||||||
Other current liabilities |
| 40,529 | 117,296 | | | 157,825 | ||||||||||||||||||
Long-term debt |
| 3,554,000 | | | | 3,554,000 | ||||||||||||||||||
Deferred income tax liabilities |
| | 1,824,483 | 7,558 | (268,066 | ) | 1,563,975 | |||||||||||||||||
Other noncurrent liabilities |
| 11,241 | 66,117 | | | 77,358 | ||||||||||||||||||
Cumulative preferred stock subject to mandatory redemption |
191,035 | | | | | 191,035 | ||||||||||||||||||
Puttable common stock |
3,250 | | | | | 3,250 | ||||||||||||||||||
Shareholders equity |
1,512,742 | 1,696,448 | 5,049,392 | 1,887 | (6,747,727 | ) | 1,512,742 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total liabilities and shareholders equity |
$ | 1,707,027 | $ | 5,397,486 | $ | 7,337,589 | $ | 53,372 | $ | (7,057,788 | ) | $ | 7,437,686 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
F-41
SAMSON RESOURCES CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF INCOME (LOSS) AND
COMPREHENSIVE INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 2014
(In thousands)
Samson Resources Corporation (Parent Guarantor) |
Samson Investment Company (Issuer) |
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Eliminations | Consolidated | |||||||||||||||||||
Total revenues |
$ | | $ | | $ | 1,177,696 | $ | | $ | | $ | 1,177,696 | ||||||||||||
Total operating expenses |
22,829 | | 3,271,816 | 488 | | 3,295,133 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating loss |
(22,829 | ) | | (2,094,120 | ) | (488 | ) | | (2,117,437 | ) | ||||||||||||||
Interest expense, net |
(3,230 | ) | (88,527 | ) | (151 | ) | | | (91,908 | ) | ||||||||||||||
Equity in earnings of subsidiaries |
(1,403,831 | ) | (1,346,929 | ) | | | 2,750,760 | | ||||||||||||||||
Other expense, net |
| | (452 | ) | (303 | ) | | (755 | ) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Income (loss) before income taxes |
(1,429,890 | ) | (1,435,456 | ) | (2,094,723 | ) | (791 | ) | 2,750,760 | (2,210,100 | ) | |||||||||||||
Income tax benefit |
(9,309 | ) | (31,625 | ) | (748,302 | ) | (283 | ) | | (789,519 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net income (loss) |
(1,420,581 | ) | (1,403,831 | ) | (1,346,421 | ) | (508 | ) | 2,750,760 | (1,420,581 | ) | |||||||||||||
Total other comprehensive income (loss), net of tax |
43,742 | 43,742 | 43,742 | | (87,484 | ) | 43,742 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total comprehensive income (loss) |
$ | (1,376,839 | ) | $ | (1,360,089 | ) | $ | (1,302,679 | ) | $ | (508 | ) | $ | 2,663,276 | $ | (1,376,839 | ) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
F-42
SAMSON RESOURCES CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF INCOME (LOSS) AND
COMPREHENSIVE INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 2013
(In thousands)
Samson Resources Corporation (Parent Guarantor) |
Samson Investment Company (Issuer) |
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Eliminations | Consolidated | |||||||||||||||||||
Total revenues |
$ | | $ | | $ | 1,082,220 | $ | 1,361 | $ | | $ | 1,083,581 | ||||||||||||
Total operating expenses |
21,734 | 7 | 2,777,378 | 1,744 | | 2,800,863 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating loss |
(21,734 | ) | (7 | ) | (1,695,158 | ) | (383 | ) | | (1,717,282 | ) | |||||||||||||
Interest income, net |
| 2 | | 13 | | 15 | ||||||||||||||||||
Equity in earnings of subsidiaries |
(1,091,401 | ) | (1,091,366 | ) | | | 2,182,767 | | ||||||||||||||||
Other expense, net |
| (49 | ) | (194 | ) | (1,822 | ) | | (2,065 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Income (loss) before income taxes |
(1,113,135 | ) | (1,091,420 | ) | (1,695,352 | ) | (2,192 | ) | 2,182,767 | (1,719,332 | ) | |||||||||||||
Income tax benefit |
(7,761 | ) | (19 | ) | (605,395 | ) | (783 | ) | | (613,958 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net income (loss) |
(1,105,374 | ) | (1,091,401 | ) | (1,089,957 | ) | (1,409 | ) | 2,182,767 | (1,105,374 | ) | |||||||||||||
Total other comprehensive income (loss), net of tax |
(5,585 | ) | (5,585 | ) | | | 5,585 | (5,585 | ) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total comprehensive income (loss) |
$ | (1,110,959 | ) | $ | (1,096,986 | ) | $ | (1,089,957 | ) | $ | (1,409 | ) | $ | 2,188,352 | $ | (1,110,959 | ) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
F-43
SAMSON RESOURCES CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF INCOME (LOSS) AND
COMPREHENSIVE INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 2012
(In thousands)
Samson Resources Corporation (Parent Guarantor) |
Samson Investment Company (Issuer) |
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Eliminations | Consolidated | |||||||||||||||||||
Total revenues |
$ | | $ | | $ | 1,156,331 | $ | 11,609 | $ | | $ | 1,167,940 | ||||||||||||
Total operating expenses |
20,564 | 96,489 | 3,336,343 | 5,811 | | 3,459,207 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Operating income (loss) |
(20,564 | ) | (96,489 | ) | (2,180,012 | ) | 5,798 | | (2,291,267 | ) | ||||||||||||||
Interest income, net |
| 30 | 127 | | | 157 | ||||||||||||||||||
Equity in earnings of subsidiaries |
(1,516,808 | ) | (1,427,079 | ) | | | 2,943,887 | | ||||||||||||||||
Loss on early extinguishment of debt |
| (44,815 | ) | | | | (44,815 | ) | ||||||||||||||||
Other income (expense), net |
| 1,705 | (996 | ) | (731 | ) | | (22 | ) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Income (loss) before income taxes |
(1,537,372 | ) | (1,566,648 | ) | (2,180,881 | ) | 5,067 | 2,943,887 | (2,335,947 | ) | ||||||||||||||
Income tax provision (benefit) |
(7,343 | ) | (49,840 | ) | (750,544 | ) | 1,809 | | (805,918 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net income (loss) |
(1,530,029 | ) | (1,516,808 | ) | (1,430,337 | ) | 3,258 | 2,943,887 | (1,530,029 | ) | ||||||||||||||
Total other comprehensive income (loss), net of tax |
6,314 | 6,314 | | | (6,314 | ) | 6,314 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total comprehensive income (loss) |
$ | (1,523,715 | ) | $ | (1,510,494 | ) | $ | (1,430,337 | ) | $ | 3,258 | $ | 2,937,573 | $ | (1,523,715 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
F-44
SAMSON RESOURCES CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2014
(In thousands)
Samson Resources Corporation (Parent Guarantor) |
Samson Investment Company (Issuer) |
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Eliminations | Consolidated | |||||||||||||||||||
Net cash provided by (used in) operating activities |
$ | (23,083 | ) | $ | (58,777 | ) | $ | 571,569 | $ | (2,152 | ) | $ | | $ | 487,557 | |||||||||
Investing activities: |
||||||||||||||||||||||||
Capital expendituresoil and gas properties |
| | (883,752 | ) | | | (883,752 | ) | ||||||||||||||||
Capital expendituresother property and equipment |
| | (27,500 | ) | | | (27,500 | ) | ||||||||||||||||
Acquisitionsoil and gas properties |
(57,631 | ) | (57,631 | ) | ||||||||||||||||||||
Proceeds from divestituresoil and gas properties |
| | 146,690 | | | 146,690 | ||||||||||||||||||
Proceeds from divestituresother property and equipment |
| | 9,892 | | | 9,892 | ||||||||||||||||||
Advances to parent/subsidiary |
| (291,213 | ) | | | 291,213 | | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net cash provided by (used in) investing activities |
| (291,213 | ) | (812,301 | ) | | 291,213 | (812,301 | ) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Financing activities: |
||||||||||||||||||||||||
Advances from issuer |
25,273 | | 263,784 | 2,156 | (291,213 | ) | | |||||||||||||||||
Proceeds from revolver |
| 539,000 | | | | 539,000 | ||||||||||||||||||
Repayment of revolver |
| (188,000 | ) | | | | (188,000 | ) | ||||||||||||||||
Debt issuance cost |
| (967 | ) | | | | (967 | ) | ||||||||||||||||
Repurchase of puttable common stock |
(2,190 | ) | | | | | (2,190 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net cash provided by (used in) financing activities |
23,083 | 350,033 | 263,784 | 2,156 | (291,213 | ) | 347,843 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net change in cash |
| 43 | 23,052 | 4 | | 23,099 | ||||||||||||||||||
Cash and cash equivalents at beginning of period |
| 238 | 399 | 90 | | 727 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Cash and cash equivalents at end of period |
$ | | $ | 281 | $ | 23,451 | $ | 94 | $ | | $ | 23,826 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
F-45
SAMSON RESOURCES CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2013
(In thousands)
Samson Resources Corporation (Parent Guarantor) |
Samson Investment Company (Issuer) |
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Eliminations | Consolidated | |||||||||||||||||||
Net cash provided by (used in) operating activities |
$ | (21,734 | ) | $ | (7 | ) | $ | 715,560 | $ | (15,512 | ) | $ | 10,320 | $ | 688,627 | |||||||||
Investing Activities: |
||||||||||||||||||||||||
Capital expendituresoil and gas properties |
| | (990,780 | ) | (40,864 | ) | | (1,031,644 | ) | |||||||||||||||
Capital expendituresother property and equipment |
(7,847 | ) | | (41,471 | ) | (2 | ) | | (49,320 | ) | ||||||||||||||
Proceeds from divestituresoil and gas properties |
| | 311,612 | | | 311,612 | ||||||||||||||||||
Proceeds from divestituresother property and equipment |
| | 5,071 | | | 5,071 | ||||||||||||||||||
Advances to parent/subsidiary |
| | | | | | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net cash used in investing activities |
(7,847 | ) | | (715,568 | ) | (40,866 | ) | | (764,281 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Financing activities: |
||||||||||||||||||||||||
Proceeds from revolver |
| 556,000 | | | | 556,000 | ||||||||||||||||||
Repayment of revolver |
| (477,000 | ) | | | | (477,000 | ) | ||||||||||||||||
Debt issuance costs |
| (2,693 | ) | | | | (2,693 | ) | ||||||||||||||||
Advances from issuer |
32,546 | (77,718 | ) | (748 | ) | 56,240 | (10,320 | ) | | |||||||||||||||
Repurchase of puttable common stock |
(2,965 | ) | | | | | (2,965 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net cash provided by (used in) financing activities |
29,581 | (1,411 | ) | (748 | ) | 56,240 | (10,320 | ) | 73,342 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net change in cash |
| (1,418 | ) | (756 | ) | (138 | ) | | (2,312 | ) | ||||||||||||||
Cash and cash equivalents at beginning of period |
| 1,656 | 1,155 | 228 | | 3,039 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Cash and cash equivalents at end of period |
$ | | $ | 238 | $ | 399 | $ | 90 | $ | | $ | 727 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
F-46
SAMSON RESOURCES CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2012
(In thousands)
Samson Resources Corporation (Parent Guarantor) |
Samson Investment Company (Issuer) |
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Eliminations | Consolidated | |||||||||||||||||||
Net cash provided by (used in) operating activities |
$ | (20,564 | ) | $ | (96,489 | ) | $ | 654,797 | $ | (15,937 | ) | $ | 10,057 | $ | 531,864 | |||||||||
Investing Activities: |
||||||||||||||||||||||||
Purchase of Predecessor business, net of cash |
(109,452 | ) | | | | | (109,452 | ) | ||||||||||||||||
Capital expendituresoil and gas properties |
| | (1,074,832 | ) | | | (1,074,832 | ) | ||||||||||||||||
Capital expendituresother property and equipment |
| | (44,423 | ) | | | (44,423 | ) | ||||||||||||||||
Proceeds from divestituresoil and gas properties |
| | 735,012 | | | 735,012 | ||||||||||||||||||
Proceeds (purchase) of other assets |
| | 3,811 | | | 3,811 | ||||||||||||||||||
Advances to parent/subsidiary |
| | | | | | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net cash used in investing activities |
(109,452 | ) | | (380,432 | ) | | | (489,884 | ) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Financing activities: |
||||||||||||||||||||||||
Proceeds from borrowings of long-term debt |
| 3,250,000 | | | | 3,250,000 | ||||||||||||||||||
Repayment of long-term debt |
| (2,250,000 | ) | | | | (2,250,000 | ) | ||||||||||||||||
Proceeds from revolver |
| 520,000 | | | | 520,000 | ||||||||||||||||||
Repayment of revolver |
| (1,640,000 | ) | | | | (1,640,000 | ) | ||||||||||||||||
Debt issuance costs |
| (51,945 | ) | | | | (51,945 | ) | ||||||||||||||||
Advances from issuer |
123,741 | 160,951 | (290,800 | ) | 16,165 | (10,057 | ) | | ||||||||||||||||
Issuance of puttable common stock |
12,375 | | | | | 12,375 | ||||||||||||||||||
Repurchase of puttable common stock |
(6,100 | ) | | | | | (6,100 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net cash provided by (used in) financing activities |
130,016 | (10,994 | ) | (290,800 | ) | 16,165 | (10,057 | ) | (165,670 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net change in cash |
| (107,483 | ) | (16,435 | ) | 228 | | (123,690 | ) | |||||||||||||||
Cash and cash equivalents at beginning of period |
| 109,139 | 17,590 | | | 126,729 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Cash and cash equivalents at end of period |
$ | | $ | 1,656 | $ | 1,155 | $ | 228 | $ | | $ | 3,039 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
F-47
Note 22. Supplemental Quarterly Financial Information (Unaudited)
The results of operations by quarter for the periods indicated are as follows:
2014 Quarter Ended | ||||||||||||||||
March 31 | June 30 | September 30 | December 31 | |||||||||||||
(In thousands) | ||||||||||||||||
Total revenues(1) |
$ | 250,928 | $ | 260,798 | $ | 340,778 | $ | 325,192 | ||||||||
Income (loss) from operations(2) |
19,137 | (301,454 | ) | (382,868 | ) | (1,452,252 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Net income (loss) |
$ | (1,022 | ) | $ | (207,822 | ) | $ | (261,813 | ) | $ | (949,924 | ) | ||||
|
|
|
|
|
|
|
|
2013 Quarter Ended | ||||||||||||||||
March 31 | June 30 | September 30 | December 31 | |||||||||||||
(In thousands) | ||||||||||||||||
Total revenues(3) |
$ | 212,901 | $ | 375,936 | $ | 250,346 | $ | 244,398 | ||||||||
Income (loss) from operations(4) |
(89,599 | ) | 127,671 | 11,766 | (1,767,120 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net income (loss) |
$ | (58,229 | ) | $ | 83,044 | $ | 6,657 | $ | (1,136,846 | ) | ||||||
|
|
|
|
|
|
|
|
(1) | Includes gain (loss) on commodity derivative contracts of $(57.3) million, $(38.3) million, $60.4 million and $116.5 million for the first, second, third and fourth quarters, respectively. |
(2) | Includes a full cost ceiling test impairment of $312.1 million, $478.5 million and $1,534.8 million for the second, third and fourth quarters, respectively. |
(3) | Includes gain (loss) on commodity derivative contracts of $(50.0) million, $72.0 million, $(47.3) million and $(33.1) million for the first, second, third and fourth quarters, respectively. |
(4) | Includes a full cost ceiling test impairment of $69.3 million, $11.1 million and $1,737.3 million for the first, second, and fourth quarters, respectively. |
Note 23. Supplemental Oil and Gas Disclosures (Unaudited)
Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities
Costs incurred in the acquisition, exploration and development activities were as follows for the specified periods (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Acquisition of properties: |
||||||||||||
Proved |
$ | 44,733 | $ | 3,638 | $ | 9,538 | ||||||
Unproved |
28,571 | 1,925 | 69,969 | |||||||||
Exploration |
57,278 | 55,525 | 45,133 | |||||||||
Development |
785,949 | 1,034,994 | 1,299,629 | |||||||||
|
|
|
|
|
|
|||||||
Total costs incurred |
$ | 916,531 | $ | 1,096,082 | $ | 1,424,269 | ||||||
|
|
|
|
|
|
Capitalized interest of $243.1 million, $341.7 million and $279.7 million for the years ended December 31, 2014, 2013 and 2012, respectively, were included as part of the cost of oil and gas properties.
Internal costs directly related to property acquisition, exploration and development of oil and gas properties totaled $30.8 million, $37.6 million and $35.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. All capitalized internal costs were included as part of the cost of oil and gas properties and included in proved properties in the consolidated balance sheets.
F-48
Capitalized Costs
Aggregate capitalized costs and accumulated depletion and impairment were as follows (in thousands):
December 31, 2014 |
December 31, 2013 |
|||||||
Proved properties |
$ | 10,569,969 | $ | 8,075,440 | ||||
Unproved properties excluded from amortization |
2,164,708 | 3,789,432 | ||||||
Uncompleted capital project costs excluded from amortization |
104,813 | 125,636 | ||||||
|
|
|
|
|||||
Gross capitalized costs |
12,839,490 | 11,990,508 | ||||||
Less: Accumulated depletion and impairment |
(8,016,867 | ) | (5,252,269 | ) | ||||
|
|
|
|
|||||
Net capitalized costs |
$ | 4,822,623 | $ | 6,738,239 | ||||
|
|
|
|
The composition of net costs excluded from amortization was as follows (in thousands):
Costs incurred: | ||||||||||||||||||||
Year Ended December 31, 2014 |
Year Ended December 31, 2013 |
Year Ended December 31, 2012 |
2011 and Prior | Total | ||||||||||||||||
Acquisition costs |
$ | 28,571 | $ | 1,925 | $ | 69,969 | $ | 1,281,262 | $ | 1,381,727 | ||||||||||
Exploration and development costs |
377 | 54,591 | 149,286 | 9,143 | 213,397 | |||||||||||||||
Capitalized interest |
243,110 | 341,719 | 66,631 | 720 | 652,180 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
$ | 272,058 | $ | 398,235 | $ | 285,886 | $ | 1,291,125 | $ | 2,247,304 | |||||||||||
|
|
|
|
|
|
|
|
|
|
The table above shows the costs excluded from amortization at December 31, 2014, 2013 and 2012, by the year in which the costs were incurred. For purposes of the table above, allocations of unproved property costs impact the oldest presented periods first before impacting later periods. Included in unproved properties excluded from amortization at December 31, 2014 are approximately $705.8 million in costs associated with our Fort Union project and $684.5 million in costs associated with our Granite Wash project. We consider each of these projects to be individually significant projects. Our Greater Green River business unit is targeting multiple intervals of stacked sand in the liquids-rich Fort Union reservoir. Our operations in the Texas Panhandle currently target the Granite Wash formation, which has multiple producing intervals and the potential for pad drilling. We expect the majority of the costs associated with these individually significant projects will be evaluated and either impaired or become subject to depletion within ten years.
Oil and Gas Reserve Quantities
Netherland, Sewell & Associates, Inc. (NSAI), our independent reserve engineers, estimated 100% of the Companys reserves at December 31, 2014, 2013 and 2012. In accordance with SEC regulations, reserves at December 31, 2014, 2013 and 2012 were estimated using the unweighted arithmetic average first-of-the-month pricing for the preceding 12-month period. We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates may change as future information becomes available.
F-49
The following is an analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located in the United States for the specified periods:
Year Ended December 31, 2014 | ||||||||||||||||
Oil (MBbl) |
Natural Gas (MMcf) |
Natural Gas Liquids (MBbl) |
Total (MMcfe) |
|||||||||||||
Proved developed and undeveloped reserves: |
||||||||||||||||
Beginning of period |
51,594 | 1,246,303 | 50,173 | 1,856,905 | ||||||||||||
Purchases of reserves in place |
280 | 34,148 | 1,664 | 45,812 | ||||||||||||
Sales of reserves |
(1,163 | ) | (37,551 | ) | (1,073 | ) | (50,962 | ) | ||||||||
Extensions and discoveries |
5,548 | 85,695 | 4,870 | 148,205 | ||||||||||||
Revisions of previous estimates |
(19,255 | ) | (107,065 | ) | (15,323 | ) | (314,536 | ) | ||||||||
Production |
(4,946 | ) | (135,812 | ) | (4,623 | ) | (193,226 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Balance as of December 31, 2014 |
32,058 | 1,085,718 | 35,688 | 1,492,198 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves: |
||||||||||||||||
Beginning of period |
20,480 | 953,254 | 25,956 | 1,231,870 | ||||||||||||
End of period |
23,170 | 953,256 | 26,734 | 1,252,680 | ||||||||||||
Proved undeveloped reserves: |
||||||||||||||||
Beginning of period |
31,114 | 293,049 | 24,217 | 625,035 | ||||||||||||
End of period |
8,888 | 132,462 | 8,954 | 239,514 |
For the year ended December 31, 2014, extensions and discoveries of proved reserves were primarily due to drilling activity in Cotton Valley and Taylor formations of our East Texas business unit of approximately 76,000 MMcfe, the Granite Wash formation of our Mid-Con West business unit of approximately 22,000 MMcfe, the Three Forks and Bakken formations of our Williston business unit of approximately 15,200 MMcfe, the Woodford and Mississippi formations of our Mid-Con East business unit of approximately 7,600 MMcfe and 6,500 MMcfe, respectively, as well as the Sussex formation of our Powder River business unit of approximately 5,200 MMcfe. Proved reserve revisions of significance for the year ended December 31, 2014, occurred as a result of robust technical review, updated geologic and engineering information, and operated and non-operated well results. Revisions in the Powder River were approximately (85,000) MMcfe, in the Mid-Con West of approximately (78,000) MMcfe, Greater Green River Basins of (69,000) MMcfe, East Texas of (61,000) MMcfe, and Williston, Mid-Con East and San Juan of (15,000) MMcfe, (11,000) MMcfe and (15,000) MMcfe, respectively.
Year Ended December 31, 2013 | ||||||||||||||||
Oil (MBbl) |
Natural Gas (MMcf) |
Natural Gas Liquids (MBbl) |
Total (MMcfe) |
|||||||||||||
Proved developed and undeveloped reserves: |
||||||||||||||||
Beginning of period |
68,309 | 1,323,484 | 46,854 | 2,014,462 | ||||||||||||
Purchases of reserves in place |
37 | 82 | 2 | 316 | ||||||||||||
Sales of reserves |
(2,895 | ) | (28,712 | ) | (826 | ) | (51,038 | ) | ||||||||
Extensions and discoveries |
13,754 | 124,063 | 9,524 | 263,731 | ||||||||||||
Revisions of previous estimates |
(22,293 | ) | (21,714 | ) | (703 | ) | (159,690 | ) | ||||||||
Production |
(5,318 | ) | (150,900 | ) | (4,678 | ) | (210,876 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Balance as of December 31, 2013 |
51,594 | 1,246,303 | 50,173 | 1,856,905 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves: |
||||||||||||||||
Beginning of period |
24,039 | 1,030,583 | 22,184 | 1,307,921 | ||||||||||||
End of period |
20,480 | 953,254 | 25,956 | 1,231,870 | ||||||||||||
Proved undeveloped reserves: |
||||||||||||||||
Beginning of period |
44,270 | 292,901 | 24,670 | 706,541 | ||||||||||||
End of period |
31,114 | 293,049 | 24,217 | 625,035 |
F-50
For the year ended December 31, 2013, extensions and discoveries of proved reserves were primarily due to extensions with respect to our assets in the Mid-Continent and East Texas regions of approximately 100,700 MMcfe and 50,200 MMcfe, respectively, and extensions relating to our assets in the Greater Green River and Powder River basins of approximately 37,100 MMcfe and 33,700 MMcfe, respectively. For the year ended December 31, 2013, revisions of previously estimated reserve quantities of oil are primarily due to revisions of our proved undeveloped reserves in the Sussex formation of the Powder River business unit of approximately 10,700 MBbls. The performance of new wells in the Sussex formation has been below expectations due to lower than anticipated initial production rates and high water rates. As a result, we had downward technical revisions in both proved developed and proved undeveloped oil reserves in the Powder River business unit.
Year Ended December 31, 2012 | ||||||||||||||||
Oil (MBbl) |
Natural Gas (MMcf) |
Natural Gas Liquids (MBbl) |
Total (MMcfe) |
|||||||||||||
Proved developed and undeveloped reserves: |
||||||||||||||||
Beginning of period |
55,996 | 2,003,805 | | 2,339,781 | ||||||||||||
Purchases of reserves in place |
4,841 | 3,834 | 614 | 36,564 | ||||||||||||
Sales of reserves |
(15,873 | ) | (16,375 | ) | (128 | ) | (112,381 | ) | ||||||||
Extensions and discoveries |
37,189 | 260,396 | 20,651 | 607,436 | ||||||||||||
Revisions of previous estimates |
(7,678 | ) | (749,378 | ) | 29,741 | (617,000 | ) | |||||||||
Production |
(6,166 | ) | (178,798 | ) | (4,024 | ) | (239,938 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Balance as of December 31, 2012 |
68,309 | 1,323,484 | 46,854 | 2,014,462 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves: |
||||||||||||||||
Beginning of period |
27,003 | 1,327,053 | | 1,489,071 | ||||||||||||
End of period |
24,039 | 1,030,583 | 22,184 | 1,307,921 | ||||||||||||
Proved undeveloped reserves: |
||||||||||||||||
Beginning of period |
28,993 | 676,752 | | 850,710 | ||||||||||||
End of period |
44,270 | 292,901 | 24,670 | 706,541 |
For the year ended December 31, 2012, extensions and discoveries of proved reserves were primarily due to extensions with respect to our assets in the Mid-Continent region and the Powder River and Williston basins of approximately 164,700 MMcfe, 110,500 MMcfe and 92,900 MMcfe, respectively, as well as extensions with respect to our Cotton Valley Sand and Ft. Union assets of approximately 116,900 MMcfe and 93,100 MMcfe, respectively. For the year ended December 31, 2012, revisions of previously estimated reserve quantities of natural gas and NGLs were impacted by the reserve report being completed on a three stream basis rather than a two stream basis as in prior periods, which created a positive revision to our NGL volumes and an equivalent negative revision to our natural gas reserves. NGLs had previously been included within the natural gas stream. Additionally, revisions to our natural gas reserves were significantly impacted by a reduction in natural gas prices during the year ended December 31, 2012, which negatively impacted proved natural gas reserves by approximately 561,900 MMcfe.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, natural gas and NGLs reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs for the years ended December 31, 2014, 2013 and 2012, are based on the unweighted arithmetic average first-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. Future income tax
F-51
expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves. The reference prices used were as follows:
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Oil (per barrel)(a) |
$ | 94.99 | $ | 96.91 | $ | 94.71 | ||||||
Natural gas (per MMBtu)(a) |
$ | 4.35 | $ | 3.67 | $ | 2.76 | ||||||
NGLs (per barrel) |
$ | 33.46 | $ | 34.47 | $ | 38.15 |
(a) | Before adjustment for market differentials. |
All wellhead prices, capital costs and operating expenses are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.
The standardized measure of discounted future net cash flows related to proved oil and natural gas are as follows (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Future cash inflows |
$ | 7,821,982 | $ | 10,446,318 | $ | 10,518,203 | ||||||
Future production costs |
(2,847,058 | ) | (3,713,708 | ) | (3,410,276 | ) | ||||||
Future development costs |
(762,655 | ) | (1,675,611 | ) | (1,978,262 | ) | ||||||
Future income tax expense |
(594,284 | ) | (420,246 | ) | (599,431 | ) | ||||||
|
|
|
|
|
|
|||||||
Future net cash flows |
3,617,985 | 4,636,753 | 4,530,234 | |||||||||
10% discount for estimated timing of cash flows |
(1,362,705 | ) | (2,024,066 | ) | (2,056,928 | ) | ||||||
|
|
|
|
|
|
|||||||
Standardized measure of discounted future net cash flows |
$ | 2,255,280 | $ | 2,612,687 | $ | 2,473,306 | ||||||
|
|
|
|
|
|
The market prices for our production decreased significantly in the last part of 2014 with continued weakness into 2015. Sustained price declines could have a significant impact on our standardized measure of discounted future net cash flows.
F-52
Changes in the standardized measure of discounted future net cash flows related to proved oil and natural gas are as follows (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Standardized measure of discounted future cash flows, beginning of year |
$ | 2,612,687 | $ | 2,473,306 | $ | 2,896,845 | ||||||
Sales and transfers of oil and gas produced, net of production costs(a) |
(807,764 | ) | (869,818 | ) | (741,254 | ) | ||||||
Extensions, discoveries, and improved recoveries, net of future production and development costs |
376,534 | 496,926 | 1,006,145 | |||||||||
Purchases and sales of reserves in place |
(18,650 | ) | (84,957 | ) | (349,933 | ) | ||||||
Revisions of quantity estimates |
(471,909 | ) | (215,244 | ) | (961,484 | ) | ||||||
Net changes in prices and cost rates |
(160,626 | ) | 473,493 | (371,885 | ) | |||||||
Previously estimated development costs incurred during the period |
256,176 | 172,129 | 43,472 | |||||||||
Changes in estimated future development costs |
(38,776 | ) | 17,557 | (108,375 | ) | |||||||
Accretion of discount |
278,598 | 271,499 | 364,615 | |||||||||
Net change in income taxes |
(88,820 | ) | 68,393 | 507,618 | ||||||||
Changes in timing and other |
317,830 | (190,597 | ) | 187,542 | ||||||||
|
|
|
|
|
|
|||||||
Standardized measure of discounted future cash flows, end of year |
$ | 2,255,280 | $ | 2,612,687 | $ | 2,473,306 | ||||||
|
|
|
|
|
|
(a) | Excluding gains and losses on derivatives. |
Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, natural gas and NGLs may differ materially from the amounts estimated.
F-53
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
2.1 | Stock Purchase Agreement among Samson Resources Corporation (f/k/a Tulip Acquisition Corporation), Samson Investment Company and the selling stockholders named therein, dated as of November 22, 2011. ** | S-4 | 333-186686 | 2.1 | 2/14/2013 | | ||||||
2.2 | Amendment No. 1 dated December 12, 2011, to Stock Purchase Agreement dated as of November 22, 2011 among Samson Resources Corporation (f/k/a Tulip Acquisition Corporation) and Samson Investment Company and the selling stockholders named therein. | S-4 | 333-186686 | 2.2 | 2/14/2013 | | ||||||
2.3 | Letter Agreement dated March 19, 2012, to Stock Purchase Agreement dated as of November 22, 2011 among Samson Resources Corporation (f/k/a Tulip Acquisition Corporation) and Samson Investment Company and the selling stockholders named therein. | S-4 | 333-186686 | 2.3 | 2/14/2013 | | ||||||
2.4 | Letter Agreement dated June 21, 2012, to Stock Purchase Agreement dated as of November 22, 2011 among Samson Resources Corporation (f/k/a Tulip Acquisition Corporation) and Samson Investment Company and the selling stockholders named therein. | S-4 | 333-186686 | 2.4 | 2/14/2013 | | ||||||
2.5 | Purchase and Sale Agreement between Samson Resources Company, as seller, and Continental Resources, Inc., as buyer, dated as of November 6, 2012. ** | S-4 | 333-186686 | 10.11 | 2/14/2013 | | ||||||
3.1 | Amended and Restated Certificate of Incorporation of Samson Resources Corporation dated December 20, 2011. | S-4 | 333-186686 | 3.1 | 2/14/2013 | | ||||||
3.2 | Amended and Restated Articles of Incorporation of Samson Investment Company dated December 21, 2011. | S-4 | 333-186686 | 3.2 | 2/14/2013 | | ||||||
3.3 | Amended and Restated Bylaws of Samson Resources Corporation as of August 1, 2012. | S-4 | 333-186686 | 3.18 | 2/14/2013 | | ||||||
3.4 | Amended Bylaws of Samson Investment Company as of December 30, 2011. | S-4 | 333-186686 | 3.19 | 2/14/2013 | | ||||||
4.1 | Indenture dated as of February 8, 2012 among Samson Investment Company, the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee. | S-4 | 333-186686 | 4.1 | 2/14/2013 | |
II-1
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
4.2 | First Supplemental Indenture, dated as of January 29, 2013, among Samson Resources Corporation, Samson Investment Company and Wells Fargo Bank, National Association, as trustee. | S-4/A | 333-186686 | 4.2 | 5/13/2014 | | ||||||
4.3 | Registration Rights Agreement, dated as of February 8, 2012, by and among Samson Investment Company, the several guarantors named therein and J.P. Morgan Securities LLC as representative of the initial purchasers named therein. | S-4 | 333-186686 | 4.2 | 2/14/2013 | | ||||||
4.4 | Amendment to the First Supplemental Indenture, dated as of July 21, 2014, among Samson Resources Corporation, Samson Investment Company and Wells Fargo Bank, National Association, as trustee. | S-4/A | 333-186686 | 4.4 | 7/21/2014 | | ||||||
10.1 | Credit Agreement, dated as of December 21, 2011, among Samson Investment Company, as the Borrower, the several Lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Collateral Agent, Swingline Lender and a Letter of Credit Issuer, Wells Fargo Bank, N.A., as Syndication Agent, and J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Lead Arrangers and J.P. Morgan Securities LLC, Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, BMO Capital Markets Corp., Barclays Capital, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Mizuho Corporate Bank, Ltd. and RBC Capital Markets as Joint Bookrunners, KKR Capital Markets LLC, as Joint Manager and Arranger. | X | ||||||||||
10.2 | First Amendment to Credit Agreement among Samson Investment Company, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, dated as of August 6, 2012. | S-4 | 333-186686 | 10.2 | 2/14/2013 | | ||||||
10.3 | Second Amendment Agreement to Credit Agreement among Samson Investment Company, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Collateral Agent, Swingline Lender and a Letter of Credit Issuer, and the several Lenders party thereto, dated as of September 7, 2012. | X |
II-2
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.4 | Third Amendment Agreement to Credit Agreement among Samson Investment Company, as the Borrower, the Guarantors party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the several Lenders party thereto, dated as of November 14, 2013. | S-4/A | 333-186686 | 10.4 | 5/13/2014 | | ||||||
10.5 | Fourth Amendment Agreement to Credit Agreement among Samson Investment Company, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the several Lenders party thereto, dated as of May 9, 2014. | S-4/A | 333-186686 | 10.5 | 5/13/2014 | | ||||||
10.6 | Fifth Amendment and Waiver Agreement to Credit Agreement among Samson Investment Company, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the several Lenders party thereto, dated as of March 18, 2015. | X | ||||||||||
10.7 | Second Lien Term Loan Credit Agreement, dated as of September 25, 2012, among Samson Investment Company, as the Borrower, the several lenders from time to time party thereto, Bank of America, N.A., as Administrative Agent and Collateral Agent, Credit Suisse Securities (USA) LLC, as Syndication Agent, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Wells Fargo Securities, LLC, BMO Capital Markets Corp., Barclays Bank PLC, Citigroup Global Markets Inc., RBC Capital Markets and Mizuho Corporate Bank, Ltd., as Joint Bookrunners, and KKR Capital Markets LLC, as Joint Manager and Arranger. | X | ||||||||||
10.8 | Amendment No. 1, dated as of December 18, 2013, to the Second Lien Term Loan Credit Agreement, dated as of September 25, 2012, among Samson Investment Company, as the Borrower, the Lenders party thereto, Bank of America, N.A., as Administrative Agent and Collateral Agent, and the various other parties thereto. | S-4/A | 333-186686 | 10.7 | 5/13/2014 | | ||||||
10.9 | Letter Agreement between Samson Resources Corporation, Kohlberg Kravis Roberts & Co. L.P., NGP Energy Capital Management, L.L.C., Crestview Advisors, L.L.C. and JD Rockies Resources Limited, dated December 21, 2011. | S-4 | 333-186686 | 10.10 | 2/14/2013 | |
II-3
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.10 | Syndication Fee Agreement, dated as of December 21, 2011, between KKR Capital Markets LLC and Samson Resources Corporation. | S-4/A | 333-186686 | 10.9 | 5/13/2014 | | ||||||
10.11 | Indemnification Agreement, dated as of December 21, 2011, among Samson Resources Corporation, Samson Investment Company, Samson Aggregator L.P., Samson Aggregator GP LLC, JD Rockies Resources Limited, Kohlberg Kravis Roberts & Co. L.P., NGP Energy Capital Management, L.L.C. and Crestview Advisors, L.L.C. | S-4/A | 333-186686 | 10.10 | 5/13/2014 | | ||||||
10.12 | Samson Resources Corporation 2011 Stock Incentive Plan. | S-4 | 333-186686 | 10.12 | 2/14/2013 | | ||||||
10.13 | Samson Resources Corporation 2011 Stock Incentive Plan, as amended on May 13, 2013. | S-4/A | 333-186686 | 10.13 | 5/13/2014 | | ||||||
10.14 | Samson Investment Company Form of Change of Control Agreement. | S-4 | 333-186686 | 10.13 | 2/14/2013 | | ||||||
10.15 | Samson Resources Corporation Form of Management Stockholders Agreement (2012). | S-4 | 333-186686 | 10.14 | 2/14/2013 | | ||||||
10.16 | Samson Resources Corporation Form of Employee Stockholders Agreement (2012). | S-4 | 333-186686 | 10.15 | 2/14/2013 | | ||||||
10.17 | Samson Resources Corporation Form of Option Award Agreement (2012). | S-4 | 333-186686 | 10.16 | 2/14/2013 | | ||||||
10.18 | Samson Resources Corporation Form of Sale Participation Agreement (2012). | S-4 | 333-186686 | 10.17 | 2/14/2013 | | ||||||
10.19 | Letter Agreement between Samson Resources Corporation, Samson Investment Company and Michael G. Daniel, dated December 10, 2012. | S-4 | 333-186686 | 10.23 | 2/14/2013 | | ||||||
10.20 | Samson Resources Special Agreement between Samson Resources Company and Brian Trimble, effective October 1, 2012. | S-4 | 333-186686 | 10.24 | 2/14/2013 | | ||||||
10.21 | Samson Resources Special Agreement between Samson Resources Company and Philip W. Cook, effective April 16, 2012. | S-4 | 333-186686 | 10.25 | 2/14/2013 | | ||||||
10.22 | Letter Agreement between Samson Resources Corporation, Samson Investment Company and David J. Adams, dated December 18, 2012. | S-4 | 333-186686 | 10.26 | 2/14/2013 | | ||||||
10.23 | Employment Agreement, effective as of April 18, 2013, between Samson Resources Corporation, Samson Investment Company and Randy L. Limbacher. | S-4/A | 333-186686 | 10.23 | 5/13/2014 | |
II-4
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.24 | Option Award Agreement, dated as of May 20, 2013, between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.24 | 5/13/2014 | | ||||||
10.25 | Restricted Stock Award Agreement, dated as of May 20, 2013, between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.25 | 5/13/2014 | | ||||||
10.26 | Executive Stockholders Agreement, dated as of April 18, 2013, between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.26 | 5/13/2014 | | ||||||
10.27 | Sale Participation Agreement, dated as of April 18, 2013, between Samson Aggregator L.P. and Randy L. Limbacher. | S-4/A | 333-186686 | 10.27 | 5/13/2014 | | ||||||
10.28 | Special Agreement, effective as of August 1, 2013, by and between Samson Resources Company and Richard E. Fraley. | S-4/A | 333-186686 | 10.28 | 5/13/2014 | | ||||||
10.29 | Special Agreement, effective as of August 5, 2013, by and between Samson Resources Company and Louis D. Jones. | S-4/A | 333-186686 | 10.29 | 5/13/2014 | | ||||||
10.30 | Samson Resources Corporation Form of Executive Stockholders Agreement. | S-4/A | 333-186686 | 10.30 | 5/13/2014 | | ||||||
10.31 | Samson Resources Corporation Form of Option Award Agreement. | S-4/A | 333-186686 | 10.31 | 5/13/2014 | | ||||||
10.32 | Samson Resources Corporation Form of Restricted Stock Award Agreement. | S-4/A | 333-186686 | 10.32 | 5/13/2014 | | ||||||
10.33 | Samson Resources Corporation Form of Sale Participation Agreement. | S-4/A | 333-186686 | 10.33 | 5/13/2014 | | ||||||
10.34 | Amendment to Employment Agreement, effective as of April 1, 2014, between Samson Resources Corporation, Samson Investment Company and Randy L. Limbacher. | S-4/A | 333-186686 | 10.34 | 6/30/2014 | | ||||||
10.35 | Amended Option Award Agreement, dated as of March 24, 2014, by and between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.35 | 6/30/2014 | | ||||||
10.36 | Amended Restricted Stock Award Agreement, dated as of March 24, 2014, by and between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.36 | 6/30/2014 | | ||||||
10.37 | Restricted Stock Award Agreement, dated as of March 24, 2014, by and between Samson Resources Corporation and Randy L. Limbacher. | S-4/A | 333-186686 | 10.37 | 6/30/2014 | | ||||||
10.38 | Special Agreement, effective as of April 1, 2014, between Samson Resources Corporation and Louis Jones. | S-4/A | 333-186686 | 10.38 | 6/30/2014 | |
II-5
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
10.39 | Samson Resources Corporation Change in Control Severance Plan for Officers, effective as of January 1, 2014. | S-4/A | 333-186686 | 10.39 | 6/30/2014 | | ||||||
10.40 | Form of Amendment to 2013 Restricted Stock Award Agreements. | S-4/A | 333-186686 | 10.40 | 6/30/2014 | | ||||||
10.41 | Form of Amendment to 2013 and 2012 Stock Option Award Agreements. | S-4/A | 333-186686 | 10.41 | 6/30/2014 | | ||||||
10.42 | Samson Resources Corporation Form of Restricted Stock Award Agreement (2014). | S-4/A | 333-186686 | 10.42 | 6/30/2014 | | ||||||
10.43 | Officer Retention Agreement, effective as of November 14, 2014, by and between Samson Resources Corporation and Randy L. Limbacher. | 10-Q | 333-186686 | 10.1 | 11/14/2014 | | ||||||
10.44 | Form of Officer Retention Agreement for Other Officers. | 10-Q | 333-186686 | 10.2 | 11/14/2014 | | ||||||
10.45 | Samson Resources Corporation Voluntary Severance Plan for Officers. | 10-Q | 333-186686 | 10.3 | 11/14/2014 | | ||||||
10.46 | Amendment to Change-in-Control Severance Plan for Officers. | 10-Q | 333-186686 | 10.4 | 11/14/2014 | | ||||||
10.47 | Amendment to Samson Resources Corporation 2011 Stock Incentive Plan. | 10-Q | 333-186686 | 10.5 | 11/14/2014 | | ||||||
10.48 | Form of Special Bonus Agreement. | 10-Q | 333-186686 | 10.6 | 11/14/2014 | | ||||||
10.49 | Second Amendment to Employment Agreement, effective as of November 14, 2014, between Samson Resources Corporation, Samson Investment Company and Randy L. Limbacher. | 10-Q | 333-186686 | 10.7 | 11/14/2014 | | ||||||
10.50 | Form of Amendment to Special Agreements. | 10-Q | 333-186686 | 10.8 | 11/14/2014 | | ||||||
10.51 | Form of Samson Resources Corporation 2015 Performance Bonus Plan. | X | ||||||||||
10.52 | Form of Bonus Award. | X | ||||||||||
10.53 | Form of Performance Award. | X | ||||||||||
10.54 | Form of Samson Resources Corporation 2015 Bonus Plan. | X | ||||||||||
10.55 | Form of Settlement, Waiver and Release Agreement. | X | ||||||||||
10.56 | Form of Release Payment. | X | ||||||||||
12.1 | Computation of Ratio of Earnings to Fixed Charges. | X | ||||||||||
21.1 | Subsidiaries of Samson Resources Corporation. | X |
II-6
Incorporated by Reference |
||||||||||||
Exhibit No. |
Exhibit Description |
Form |
SEC File No. |
Exhibit |
Filing Date |
Filed Herewith* | ||||||
23.1 | Consent of Netherland, Sewell & Associates, Inc. | X | ||||||||||
31.1 | Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
31.2 | Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
32.1 | Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated March 31, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
32.2 | Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated March 31, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
99.1 | Summary Report of Netherland, Sewall & Associates, Inc. relating to December 31, 2014 Reserve Report. | X | ||||||||||
99.2 | Summary Report of Netherland, Sewall & Associates, Inc. relating to December 31, 2013 Reserve Report. | S-4/A | 333-186686 | 99.5 | 5/13/2014 | | ||||||
99.3 | Summary Report of Netherland, Sewall & Associates, Inc. relating to December 31, 2012 Reserve Report. | S-4/A | 333-186686 | 99.6 | 5/13/2014 | | ||||||
101.INS | XBRL Instance Document. | X | ||||||||||
101.SCH | XBRL Taxonomy Schema Document. | X | ||||||||||
101.CAL | XBRL Calculation Linkbase Document. | X | ||||||||||
101.LAB | XBRL Label Linkbase Document. | X | ||||||||||
101.PRE | XBRL Presentation Linkbase Document. | X | ||||||||||
101.DEF | XBRL Definition Linkbase Document. | X |
* | Or furnished, in the case of Exhibits 32.1 and 32.2. |
** | The registrant agrees to furnish supplementally a copy of any omitted schedule or exhibit to the agreement to the commission upon request. |
II-7