UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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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
OR
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¨ |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 001-12719
GOODRICH PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware |
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76-0466193 |
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(State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer Identification No.) |
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801 Louisiana, Suite 700 Houston, Texas |
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77002 |
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(Address of principal executive offices) |
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(Zip Code) |
(Registrant’s telephone number, including area code) (713) 780-9494
Securities Registered Pursuant to Section 12(b) of the Act:
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Common Stock, par value $0.20 per share |
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New York Stock Exchange |
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Depositary Shares, Each Representing 1/1000 Interest in a Share of |
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New York Stock Exchange |
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Depositary Shares, Each Representing 1/1000 Interest in a Share of |
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New York Stock Exchange |
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(Title of Each Class) |
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(Name of Each Exchange) |
Securities Registered Pursuant to Section 12(g) of the Act:
Series B Preferred Stock, par value $1.00 per share
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 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 Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer |
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x |
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Accelerated filer |
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¨ |
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Non-accelerated filer |
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¨ |
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Smaller reporting company |
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¨ |
Indicate by check mark whether the Registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No x
The aggregate market value of Common Stock, par value $0.20 per share (Common Stock), held by non-affiliates (based upon the closing sales price on the New York Stock Exchange on June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $963.5 million. The number of shares of the registrant’s common stock outstanding as of February 26, 2015 was 45,109,912.
Documents Incorporated By Reference:
Portions of Goodrich Petroleum Corporation’s definitive Proxy Statement, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2014, are incorporated by reference in Part III of this Form 10-K.
GOODRICH PETROLEUM CORPORATION
ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED
December 31, 2014
2
PART I
Items 1. and 2.Business and Properties
General
Goodrich Petroleum Corporation, a Delaware corporation (together with its subsidiary, “we,” “our,” or “the Company”) formed in 1995, is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Southwest Mississippi and Southeast Louisiana which includes the Tuscaloosa Marine Shale Trend (“TMS”) (ii) South Texas, which includes the Eagle Ford Shale Trend, and (iii) Northwest Louisiana and East Texas, which includes the Haynesville Shale. Due to the depressed natural gas price environment, we are concentrating the vast majority of our development efforts on existing leased acreage within formations that are prospective for oil. We own interests in 260 producing oil and natural gas wells located in 43 fields in eight states. At December 31, 2014, we had estimated proved reserves of approximately 273.7 Bcfe, comprised of 104.8 Bcf of natural gas, 1.0 MMBbls of NGLs and 27.1 MMBbls of oil and condensate.
We operate as one segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined by accounting standards related to disclosures about segments of an enterprise.
Available Information
Our principal executive offices are located at 801 Louisiana Street, Suite 700, Houston, Texas 77002.
Our website address is http://www.goodrichpetroleum.com. We make available, free of charge through the Investor Relations portion of our website, our annual reports on Form 10-K, proxy statement, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). Reports of beneficial ownership filed pursuant to Section 16(a) of the Exchange Act are also available on our website. Information contained on our website is not part of this report.
We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
As used herein, the following terms have specific meanings as set forth below:
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Bbls |
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Barrels of crude oil or other liquid hydrocarbons |
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Bcf |
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Billion cubic feet |
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Bcfe |
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Billion cubic feet equivalent |
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Boe |
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Barrel of crude oil equivalent |
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MBbls |
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Thousand barrels of crude oil or other liquid hydrocarbons |
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Mcf |
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Thousand cubic feet of natural gas |
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Mcfe |
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Thousand cubic feet equivalent |
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MMBbls |
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Million barrels of crude oil or other liquid hydrocarbons |
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MMBtu |
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Million British thermal units |
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Mmcf |
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Million cubic feet of natural gas |
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Mmcfe |
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Million cubic feet equivalent |
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MMBoe |
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Million barrels of crude oil or other liquid hydrocarbons equivalent |
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NGL |
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Natural gas liquids |
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U.S. |
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United States |
Crude oil and other liquid hydrocarbons are converted into cubic feet of natural gas equivalent based on six Mcf of natural gas to one barrel of crude oil or other liquid hydrocarbons.
3
Development well is a well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive.
Dry hole is an exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Economically producible as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil-and-natural gas producing activities.
Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
Exploratory well is 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. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.
Farm-in or farm-out is an agreement whereby the owner of a working interest in an oil and natural gas lease or license assigns the working interest or a portion thereof to another party who desires to drill on the leased or licensed acreage. Generally, the assignee is required to drill one or more wells to earn its interest in the acreage. The assignor (the “farmor”) usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in”, while the interest transferred by the assignor is a “farm-out”.
Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. The SEC provides a complete definition of field in Rule 4-10 (a) (15).
PV-10 is the pre-tax present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying the 12-month average price for the year and holding that price constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). PV-10 is not a financial measure that is in accordance with accounting principles generally accepted in the United States (“US GAAP”). The SEC methodology for computing the 12-month average price is discussed in the definition of “Proved reserves” below.
Productive well is an exploratory, development or extension well that is not a dry well.
Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. As used in this definition, “existing economic conditions” include prices and costs at which economic producibility from a reservoir is to be determined. The prices shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. The SEC provides a complete definition of proved reserves in Rule 4-10 (a) (22) of Regulation S-X.
Developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well.
Reasonable certainty means a high degree of confidence that the quantities will be recovered, if deterministic methods are used. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease. The deterministic method of estimating reserves or resources uses a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation. The probabilistic method of estimation of reserves or
4
resources uses the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) to generate a full range of possible outcomes and their associated probabilities of occurrence.
Reserves are 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. In addition, there must exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.
Undeveloped reserves are 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. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover is a series of operations on a producing well to restore or increase production.
Gross well or acre is a well or acre in which the registrant owns a working interest. The number of gross wells is the total number of wells in which the registrant owns a working interest.
Net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions of whole numbers.
5
Oil and Natural Gas Operations and Properties
Overview. As of December 31, 2014, nearly all of our proved oil and natural gas reserves were located in Louisiana, Texas and Mississippi. We spent substantially all of our 2014 capital expenditures of $333.3 million in these areas, with $263.0 million, or 79%, spent on the TMS, $52.6 million, or 16%, spent on the Eagle Ford Shale Trend, and $16.2 million, or 5% spent on the Haynesville Shale Trend. Our total capital expenditures, including accrued costs for services performed during 2014 consist of $305.5 million for drilling and completion costs, $23.2 million for leasehold acquisitions and extensions, $4.2 million for facilities, infrastructure and equipment and $0.4 million for asset retirement obligation.
6
The table below details our acreage positions, average working interest and producing wells as of December 31, 2014.
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Average |
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Producing |
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Producing |
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Acreage |
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Well |
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Wells at |
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As of December 31, 2014 |
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Working |
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December 31, |
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Field or Area |
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Gross |
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Net |
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Interest |
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2014 |
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Tuscaloosa Marine Shale Trend |
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460,660 |
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327,495 |
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63% |
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34 |
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Eagle Ford Shale Trend |
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44,370 |
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29,914 |
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67% |
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79 |
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Haynesville Shale Trend |
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66,664 |
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37,424 |
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39% |
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90 |
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Other |
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33,125 |
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11,667 |
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47% |
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57 |
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Tuscaloosa Marine Shale Trend
As of December 31, 2014, we have acquired approximately 460,700 gross (327,500 net) lease acres in the Tuscaloosa Marine Shale Trend, an emerging oil shale play in Southwest Mississippi and Southeast Louisiana. During 2014, we conducted drilling operations on 22 gross (16 net) wells and added 17 gross (12 net) wells to production in the TMS.
Eagle Ford Shale Trend
As of December 31, 2014, we have acquired or farmed-in leases totaling approximately 44,400 gross (29,900 net) lease acres. In 2010, we began development and production activity in the Eagle Ford Shale and Buda Lime formations (“Eagle Ford Shale Trend”) in La Salle and Frio Counties located in South Texas. During 2014, we conducted drilling operations on 6 gross (4 net) wells in the Eagle Ford Shale Trend.
Haynesville Shale Trend
As of December 31, 2014, we have acquired or farmed-in leases totaling approximately 66,700 gross (37,400 net) acres in the Haynesville Shale. During 2014, we conducted drilling operations on 1 gross (1 net) well in the Angelina River Trend portion of our acreage position. Our Haynesville Shale drilling activities are located in leasehold areas in East Texas and Northwest Louisiana.
Other
As of December 31, 2014, we maintained ownership interests in acreage and/or wells in several additional fields, including the Midway field in San Patricio County, Texas and the Garfield Unit in Kalkaska County, Michigan.
See “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K for additional information on our recent operations and plans for 2015 in the Tuscaloosa Marine Shale Trend, Eagle Ford Shale and Haynesville Shale Trends.
7
Oil and Natural Gas Reserves
The following tables set forth summary information with respect to our proved reserves as of December 31, 2014 and 2013, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) and by Ryder Scott Company (“RSC”) our independent reserve engineers. Approximately 35% and 65% of the proved reserves estimates shown herein at December 31, 2014 have been independently prepared by NSAI and RSC, respectively. NSAI prepared the estimates on all our proved reserves as of December 31, 2014 on properties other than in the TMS and the Eagle Ford Shale Trend areas. RSC prepared the estimate of proved reserves as of December 31, 2014 for our TMS and Eagle Ford Shall Trend areas. Copies of the summary reserve reports of NSAI and RSC as of December 31, 2014 are included as exhibits to this Annual Report on Form 10-K. For additional information see Supplemental Information “Oil and Natural Gas Producing Activities (Unaudited)” to our consolidated financial statements in Part II Item 8 of this Annual Report on Form 10-K.
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Proved Reserves at December 31, 2014 |
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Developed Producing |
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Developed Non-Producing |
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Undeveloped |
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Total |
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(dollars in thousands) |
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Net Proved Reserves: |
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Oil (MBbls) (1) |
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9,457 |
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634 |
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16,977 |
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27,068 |
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NGL (MBbls) (2) (3) |
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624 |
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4 |
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447 |
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1,075 |
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Natural Gas (Mmcf) |
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58,111 |
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2,597 |
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44,124 |
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104,832 |
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Natural Gas Equivalent (Mmcfe) (4) |
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118,595 |
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6,424 |
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148,670 |
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273,689 |
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Estimated Future Net Cash Flows |
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$ |
1,328,750 |
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PV-10 (5) |
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$ |
650,584 |
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Discounted Future Income Taxes |
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(5,848 |
) |
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Standardized Measure of Discounted Net Cash Flows (5) |
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$ |
644,736 |
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Proved Reserves at December 31, 2013 |
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Developed Producing |
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Developed Non-Producing |
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Undeveloped |
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Total |
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(dollars in thousands) |
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Net Proved Reserves: |
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Oil (MBbls) (1) |
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7,738 |
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5 |
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6,335 |
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14,078 |
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NGL (MBbls) (2) (3) |
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2,264 |
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93 |
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3,996 |
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6,353 |
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Natural Gas (Mmcf) |
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112,682 |
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4,502 |
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212,432 |
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329,616 |
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Natural Gas Equivalent (Mmcfe) (4) |
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172,695 |
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5,091 |
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274,417 |
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452,203 |
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Estimated Future Net Cash Flows |
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$ |
1,067,708 |
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PV-10 (5) |
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$ |
472,268 |
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Discounted Future Income Taxes |
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(4,121 |
) |
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Standardized Measure of Discounted Net Cash Flows (5) |
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$ |
468,147 |
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(1) |
Includes condensate. |
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(2) |
NGL reserves for 2014 include TMS and Eagle Ford Shale Trend fields and in 2013 included TMS, Eagle Ford Shale Trend, West Brachfield, North Minden and Beckville fields. |
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(3) |
Our production and sales volumes are accounted for and disclosed based on the wet gas stream at the point of sale. We report no NGL production, as NGLs are processed after the point of sale. However, we share and receive the pricing benefit of the revenue stream of the gas through the processing. We believe that presenting NGLs separately from natural gas and oil in our reserve report provides more information for our investors. The presentation of NGLs as a separate commodity more accurately presents to investors our economic interest in those NGLs separated, produced and sold from the wet gas streams (which we realize through our sharing in the revenue stream attributable to the processed NGLs). These commodities have separate pricing that is monitored in the marketplace. |
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(4) |
Based on ratio of six Mcf of natural gas per Bbl of oil and per Bbl of NGLs. |
8
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(5) |
PV-10 represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. PV-10 of our total year-end proved reserves is considered a non-US GAAP financial measure as defined by the SEC. We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. See the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above. |
The following table presents our reserves by targeted geologic formation in Mmcfe.
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December 31, 2014 |
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Area |
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Proved Developed |
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Proved Undeveloped |
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Proved Reserves |
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% of Total |
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Tuscaloosa Marine Shale Trend |
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31,796 |
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83,536 |
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115,332 |
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42 |
% |
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Eagle Ford Shale Trend |
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37,135 |
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25,254 |
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62,389 |
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23 |
% |
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Haynesville Shale Trend |
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54,049 |
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39,880 |
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93,929 |
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34 |
% |
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Other |
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2,039 |
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— |
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2,039 |
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1 |
% |
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Total |
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125,019 |
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148,670 |
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273,689 |
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100 |
% |
Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Therefore, the PV-10 amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to our properties.
In accordance with the guidelines of the SEC, our independent reserve engineers’ estimates of future net revenues from our estimated proved reserves, and the PV-10 and standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period of January 2014 through December 2014, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For reserves at December 31, 2014, the average twelve month prices used were $4.35 per MMBtu of natural gas, $94.99 per Bbl of crude oil/condensate and $44.84 per Bbl of natural gas liquids. These prices do not include the impact of hedging transactions, nor do they include the adjustments that are made for applicable transportation and quality differentials, and price differentials between natural gas liquids and oil, which are deducted from or added to the index prices on a well by well basis in estimating our proved reserves and related future net revenues.
Our proved reserve information as of December 31, 2014 included in this Annual Report on Form 10-K was estimated by our independent petroleum engineers, NSAI and RSC, in accordance with petroleum engineering and evaluation principles and definitions and guidelines set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserve Information promulgated by the Society of Petroleum Engineers. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Our principal engineer has over 30 years of experience in the oil and natural gas industry, including over 25 years as a reserve evaluator, trainer or manager. Further professional qualifications of our principal engineer include a degree in petroleum engineering, extensive internal and external reserve training, and experience in asset evaluation and management. In addition, the principal engineer is an active participant in professional industry groups and has been a member of the Society of Petroleum Engineers for over 30 years.
Our estimates of proved reserves are made by NSAI and RSC, as our independent petroleum engineers. Our internal professional staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria is provided to them. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves.
9
We consider providing independent fully engineered third-party estimates of reserves from nationally reputable petroleum engineering firms, such as NSAI and RSC, to be the best control in ensuring compliance with Rule 4-10 of Regulation S-X for reserve estimates.
While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the NSAI and RSC reserve reports are reviewed by our senior management with representatives of NSAI and RSC and our internal technical staff. Additionally, our senior management reviews and approves any internally estimated significant changes to our proved reserves semi-annually.
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, NSAI and RSC employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, available downhole and production data, seismic data and well test data.
Our total proved reserves at December 31, 2014, as estimated by NSAI and RSC, were 273.7 Bcfe, consisting of 104.8 Bcf of natural gas, 1.0 MMBbls of NGLs and 27.1 MMBbls of oil and condensate. In 2014 we added approximately 91.6 Bcfe related to the TMS and 8.8 Bcfe related to the Eagle Ford Shale Trend. We had negative revisions of approximately 116.3 Bcfe, divestitures of 135.8 Bcfe and produced 26.8 Bcfe in 2014. The vast majority of our negative revisions related to transfers of 103.1 Bcfe of proved undeveloped cases out of the proved category.
Our proved undeveloped reserves at December 31, 2014 were 148.7 Bcfe or 54.3% of our total proved reserves, consisting of 44.1 Bcf of natural gas, 0.4 MMBbls of NGLs and 17.0 MMBbls of oil and condensate. In 2014, we added approximately 3.9 Bcfe related to the Eagle Ford Shale Trend and 63.6 Bcfe related to the TMS. We had negative revisions of 91.7 Bcfe and we developed approximately 3.2 Bcfe, or 1.2% of our total proved undeveloped reserves booked as of December 31, 2013 through the drilling of 3 gross (2.3 net) development wells at an aggregate capital cost of approximately $37.5 million. Of the proved undeveloped reserves in our December 31, 2014 reserve reports, none have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves and none are scheduled for commencement of development on a date more than five years from the date the reserves were initially booked as proved undeveloped.
Productive Wells
The following table sets forth the number of productive wells in which we maintain ownership interests as of December 31, 2014:
|
|
|
Oil |
|
|
Natural Gas |
|
|
Total |
|
|||||||||||||||
|
|
|
Gross (1) |
|
|
Net (2) |
|
|
Gross (1) |
|
|
Net (2) |
|
|
Gross (1) |
|
|
Net (2) |
|
||||||
|
Southeast Louisiana (3) |
|
|
14 |
|
|
|
10 |
|
|
|
— |
|
|
|
— |
|
|
|
14 |
|
|
|
10 |
|
|
Southwest Mississippi (3) |
|
|
20 |
|
|
|
11 |
|
|
|
— |
|
|
|
— |
|
|
|
20 |
|
|
|
11 |
|
|
South Texas |
|
|
79 |
|
|
|
53 |
|
|
|
— |
|
|
|
— |
|
|
|
79 |
|
|
|
53 |
|
|
East Texas |
|
|
1 |
|
|
|
— |
|
|
|
8 |
|
|
|
5 |
|
|
|
9 |
|
|
|
5 |
|
|
Northwest Louisiana |
|
|
— |
|
|
|
— |
|
|
|
112 |
|
|
|
46 |
|
|
|
112 |
|
|
|
46 |
|
|
Other |
|
|
12 |
|
|
|
3 |
|
|
|
14 |
|
|
|
— |
|
|
|
26 |
|
|
|
3 |
|
|
Total Productive Wells |
|
|
126 |
|
|
|
77 |
|
|
|
134 |
|
|
|
51 |
|
|
|
260 |
|
|
|
128 |
|
|
(1) |
Royalty and overriding interest wells that have immaterial values are excluded from the above table. As of December 31, 2014, only three wells with royalty-only and overriding interests-only are included. |
|
(2) |
Net working interest. |
|
(3) |
Tuscaloosa Marine Shale producing wells. |
Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline connections. A gross well is a well in which we maintain an ownership interest, while a net well is deemed to exist when the sum of the fractional working interests owned by us equals one. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, four wells had completions in multiple producing horizons.
10
Acreage
The following table summarizes our gross and net developed and undeveloped acreage under lease as of December 31, 2014. Acreage in which our interest is limited to a royalty or overriding royalty interest is excluded from the table.
|
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|||||||||||||||
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
||||||
|
Southwest Mississippi |
|
|
17,055 |
|
|
|
11,300 |
|
|
|
96,084 |
|
|
|
64,738 |
|
|
|
113,139 |
|
|
|
76,038 |
|
|
Southeast Louisiana |
|
|
23,025 |
|
|
|
15,273 |
|
|
|
324,496 |
|
|
|
236,184 |
|
|
|
347,521 |
|
|
|
251,457 |
|
|
South Texas |
|
|
11,456 |
|
|
|
7,804 |
|
|
|
32,915 |
|
|
|
22,110 |
|
|
|
44,371 |
|
|
|
29,914 |
|
|
East Texas |
|
|
37,653 |
|
|
|
13,017 |
|
|
|
20,936 |
|
|
|
15,355 |
|
|
|
58,589 |
|
|
|
28,372 |
|
|
Northwest Louisiana |
|
|
39,087 |
|
|
|
20,515 |
|
|
|
— |
|
|
|
— |
|
|
|
39,087 |
|
|
|
20,515 |
|
|
Other |
|
|
2,103 |
|
|
|
195 |
|
|
|
9 |
|
|
|
9 |
|
|
|
2,112 |
|
|
|
204 |
|
|
Total |
|
|
130,379 |
|
|
|
68,104 |
|
|
|
474,440 |
|
|
|
338,396 |
|
|
|
604,819 |
|
|
|
406,500 |
|
Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to the extent that would permit the production of commercial quantities of natural gas or oil, regardless of whether or not such acreage contains proved reserves. As is customary in the oil and natural gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the remaining primary term of such a lease. The oil and natural gas leases in which we have an interest are for varying primary terms; however, most of our developed lease acreage is beyond the primary term and is held so long as natural gas or oil is produced.
Lease Expirations
Our undeveloped lease acreage, excluding optioned acreage, will expire during the next four years, unless the leases are converted into producing units or extended prior to lease expiration. The following table sets forth the lease expirations as of December 31, 2014:
|
Year |
|
Net Acreage |
|
|
|
2015 |
|
|
74,390 |
|
|
2016 |
|
|
124,430 |
|
|
2017 |
|
|
45,925 |
|
|
2018 |
|
|
14,321 |
|
Operator Activities
We operate a majority of our producing properties by value, and will generally seek to become the operator of record on properties we drill or acquire. Chesapeake Energy Corporation (“Chesapeake”) continues to operate our jointly-owned Northwest Louisiana acreage in the Haynesville Shale.
11
Drilling Activities
The following table sets forth our drilling activities for the last three years. As denoted in the following table, “gross” wells refer to wells in which a working interest is owned, while a “net” well is deemed to exist when the sum of the fractional working interests we own in gross wells equals one.
|
|
|
Year Ended December 31, |
|
|||||||||||||||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||||||||||||||
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
||||||
|
Development Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
19 |
|
|
|
13.0 |
|
|
|
14 |
|
|
|
9.3 |
|
|
|
40 |
|
|
|
25.3 |
|
|
Non-Productive |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Total |
|
|
19 |
|
|
|
13.0 |
|
|
|
14 |
|
|
|
9.3 |
|
|
|
40 |
|
|
|
25.3 |
|
|
Exploratory Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
4 |
|
|
|
3.2 |
|
|
|
8 |
|
|
|
4.1 |
|
|
|
5 |
|
|
|
1.0 |
|
|
Non-Productive |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1 |
|
|
|
0.8 |
|
|
Total |
|
|
4 |
|
|
|
3.2 |
|
|
|
8 |
|
|
|
4.1 |
|
|
|
6 |
|
|
|
1.8 |
|
|
Total Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
23 |
|
|
|
16.2 |
|
|
|
22 |
|
|
|
13.4 |
|
|
|
45 |
|
|
|
26.3 |
|
|
Non-Productive |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1 |
|
|
|
0.8 |
|
|
Total |
|
|
23 |
|
|
|
16.2 |
|
|
|
22 |
|
|
|
13.4 |
|
|
|
46 |
|
|
|
27.1 |
|
At December 31, 2014, we had 6 gross (4.5 net) development wells and 1 gross (1 net) exploration wells in progress of being drilled or completed.
Net Production, Unit Prices and Costs
The following table presents certain information with respect to oil and natural gas production attributable to our interests in all of our properties (including two fields which have attributed more than 15% of our total proved reserves as of December 31, 2014), the revenue derived from the sale of such production, average sales prices received and average production costs during each of the years in the three-year period ended December 31, 2014. See Item 8 of this Form 10-K for disclosure of revenues, profits and total assets for the years ended December 31, 2014, 2013 and 2012.
|
|
|
Sales Volumes |
|
|
Average Sales Prices (1) |
|
|
|
|
|
|
Average |
|
|||||||||||||||||||
|
|
|
Natural Gas Mmcf |
|
|
Oil & Condensate MBbls |
|
|
Total Mmcfe |
|
|
Natural Gas Mcf |
|
|
Oil & Condensate Per Bbl |
|
|
Total Per Mcfe |
|
|
% of Total Revenue |
|
|
Production Cost (2) Per Mcfe |
|
||||||||
|
For Year 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TMS |
|
|
— |
|
|
|
738 |
|
|
|
4,426 |
|
|
$ |
- |
|
|
$ |
90.55 |
|
|
$ |
15.09 |
|
|
|
32% |
|
|
$ |
1.07 |
|
|
Eagle Ford Shale Trend |
|
|
1,321 |
|
|
|
928 |
|
|
|
6,888 |
|
|
|
5.70 |
|
|
|
89.69 |
|
|
|
13.31 |
|
|
|
44% |
|
|
|
1.63 |
|
|
Haynesville Shale Trend |
|
|
10,176 |
|
|
|
1 |
|
|
|
10,179 |
|
|
|
3.08 |
|
|
|
86.36 |
|
|
|
3.08 |
|
|
|
15% |
|
|
|
0.44 |
|
|
Other |
|
|
3,483 |
|
|
|
26 |
|
|
|
3,638 |
|
|
|
5.01 |
|
|
|
90.83 |
|
|
|
5.72 |
|
|
|
9% |
|
|
|
2.50 |
|
|
Total |
|
|
14,980 |
|
|
|
1,693 |
|
|
|
25,131 |
|
|
$ |
3.75 |
|
|
$ |
90.08 |
|
|
$ |
8.30 |
|
|
|
100% |
|
|
$ |
1.17 |
|
|
For Year 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TMS |
|
|
— |
|
|
|
165 |
|
|
|
990 |
|
|
$ |
- |
|
|
$ |
105.29 |
|
|
$ |
17.58 |
|
|
|
9% |
|
|
$ |
1.02 |
|
|
Eagle Ford Shale Trend |
|
|
1,129 |
|
|
|
1,132 |
|
|
|
7,919 |
|
|
|
5.66 |
|
|
|
101.56 |
|
|
|
15.32 |
|
|
|
61% |
|
|
|
1.61 |
|
|
Haynesville Shale Trend |
|
|
14,406 |
|
|
|
1 |
|
|
|
14,409 |
|
|
|
3.00 |
|
|
|
100.05 |
|
|
|
3.01 |
|
|
|
22% |
|
|
|
0.40 |
|
|
Other |
|
|
4,225 |
|
|
|
40 |
|
|
|
4,467 |
|
|
|
3.44 |
|
|
|
98.26 |
|
|
|
3.70 |
|
|
|
8% |
|
|
|
1.07 |
|
|
Total |
|
|
19,760 |
|
|
|
1,338 |
|
|
|
27,785 |
|
|
$ |
3.35 |
|
|
$ |
101.96 |
|
|
$ |
7.29 |
|
|
|
100% |
|
|
$ |
0.98 |
|
|
For Year 2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Haynesville Shale Trend |
|
|
15,395 |
|
|
|
1 |
|
|
|
15,401 |
|
|
$ |
2.20 |
|
|
$ |
97.28 |
|
|
$ |
2.20 |
|
|
|
19% |
|
|
$ |
0.27 |
|
|
Eagle Ford Shale Trend |
|
|
1,142 |
|
|
|
960 |
|
|
|
6,902 |
|
|
|
4.26 |
|
|
|
100.01 |
|
|
|
14.64 |
|
|
|
55% |
|
|
|
0.81 |
|
|
Other |
|
|
8,307 |
|
|
|
134 |
|
|
|
9,112 |
|
|
|
4.06 |
|
|
|
99.26 |
|
|
|
5.25 |
|
|
|
26% |
|
|
|
1.41 |
|
|
Total |
|
|
24,844 |
|
|
|
1,095 |
|
|
|
31,415 |
|
|
$ |
2.86 |
|
|
$ |
99.91 |
|
|
$ |
5.75 |
|
|
|
100% |
|
|
$ |
0.83 |
|
|
(1) |
Excludes the impact of commodity derivatives. |
|
(2) |
Excludes ad valorem and severance taxes. |
12
Oil and Natural Gas Marketing and Major Customers
Marketing. Our natural gas production is sold under spot or market-sensitive contracts to various natural gas purchasers on short-term contracts. Our oil production is sold to various purchasers under short-term rollover agreements based on current market prices.
Customers. Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2014, 2013 and 2012 are as follows:
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
BP Energy Company |
|
|
46% |
|
|
|
64% |
|
|
|
34% |
|
|
Genesis Crude Oil LP |
|
|
11% |
|
|
|
7% |
|
|
|
— |
|
|
Flint Hill Resources, LLC |
|
|
— |
|
|
|
— |
|
|
|
15% |
|
Competition
The oil and natural gas industry is highly competitive. Major and independent oil and natural gas companies, drilling and production acquisition programs and individual producers and operators are active bidders for desirable oil and natural gas properties, as well as the equipment and labor required to operate those properties. Many competitors have financial resources substantially greater than ours, and staffs and facilities substantially larger than us.
Employees
At February 26, 2015, we had 105 full-time employees in our Houston administrative office and our two field offices, none of whom is represented by any labor union. We closed our Shreveport office on December 31, 2013. We regularly use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection, and well testing.
Regulations
The availability of a ready market for any oil and natural gas production depends upon numerous factors beyond our control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or the lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies as well.
Environmental and Occupational Health and Safety Matters
General
Our operations are subject to stringent and complex federal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these laws and regulations may require the acquisition of permits before drilling or other related activity commences, restrict the type, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling and production activities on certain lands lying within wilderness, wetlands and other protected areas, impose specific health and safety criteria addressing worker protection, and impose substantial liabilities for pollution arising from drilling and production operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit some or all of our operations.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and
13
consequently affects profitability. Additionally, the trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and, any changes in environmental laws and regulations that result in more stringent and costly well construction, drilling, waste management or completion activities or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business. While we believe that we are in substantial compliance with current applicable federal and state environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations or financial condition, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results.
The following is a summary of the more significant existing environmental laws to which our business operations are subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.
Hazardous Substances and Wastes
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred, and companies that disposed or arranged for the disposal of hazardous substances released at the site. Under CERCLA, these persons may be subject to joint and several, strict liabilities for remediation cost at the site, natural resource damages and for the costs of certain health studies. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. We generate materials in the course of our operations that are regulated as hazardous substances.
We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes that impose stringent requirements related to the handling and disposal of non-hazardous and hazardous wastes. There exists an exclusion under RCRA from the definition of hazardous wastes for drilling fluids, produced waters and certain other wastes generated in the exploration, development or production of oil and natural gas, efforts have been made from time to time to remove this exclusion such that those wastes would be regulated under the more rigorous RCRA hazardous waste standards. A loss of this RCRA exclusion could result in increased costs to us and the oil and gas industry in general to manage and dispose of generated wastes.
We currently own or lease, and in the past have owned or leased, properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes and petroleum hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties whose treatment and disposal of hazardous substances, wastes and petroleum hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.
Water Discharges and Subsurface Injections
The Federal Water Pollution Control Act, as amended, (“Clean Water Act”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (“EPA”) or an analogous state agency. Spill prevention, control and countermeasure (“SPCC”) plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements related to the prevention of oil spills into navigable waters as well as liabilities for oil cleanup costs, natural resource damages and a variety of public and private damages that may result from such oil spills.
The disposal of oil and natural gas wastes into underground injection wells are subject to the federal Safe Drinking Water Act, as amended (“SDWA”), and analogous state laws. The SDWA’s Underground Injection Control Program establishes requirements for
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permitting, testing, monitoring, recordkeeping and reporting of injection well activities as well as a prohibition against the migration of fluid containing any contaminants into underground sources of drinking water. State programs may have analogous permitting and operational requirements. In response to concerns related to increased seismic activity in the vicinity of injection wells, regulators in some states are considering additional requirements related to seismic safety. For example, the Texas Railroad Commission (“RRC”) adopted new oil and gas permit rules in October 2014 for wells used to dispose of saltwater and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to conduct continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position. In addition, any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for property damages and personal injury.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas from tight formations such as shales. The process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel and issued guidance in February 2014 related to such activities. Moreover, the EPA has promulgated rules under the federal Clean Air Act (“CAA”) requiring operators to use “green completions” to capture the emission of volatile organic compounds from well completion activities involving the use of hydraulic fracturing. The rules also regulate emissions from new or modified compressors, dehydrators, storage tanks, and other production equipment. Also, the EPA issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act in May 2014 seeking comment on potential rules that would require companies to disclose the chemical additives used in their hydraulic fracturing fluids.
In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report expected to be issued for peer review and comment sometime in the first half of 2015. The EPA has also announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities sometime in the first half of 2015. These results of studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Louisiana and Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Moreover, some states and local governments have enacted laws or regulations limiting hydraulic fracturing within their borders or prohibiting the activity altogether. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
Air Emissions
The CAA and comparable state laws, regulate emissions of various air pollutants from many sources in the United States, including crude oil and natural gas production activities through air emissions standards, construction and operating programs and the imposition of other compliance requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, the EPA has promulgated rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants
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(“NESHAP”) programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. Compliance with these requirements could increase our costs of development and production, which costs could be significant.
Climate Change
Certain scientific studies have found that emissions of carbon dioxide, methane and other “greenhouse gases” are contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA determined that greenhouse gases present an endangerment to public health and the environment and has issued regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. Recently, the EPA finalized modifications to its GHG reporting rules that would require covered entities to report emissions on an individual GHG basis. In addition, the EPA has proposed a rule that would expand the agency’s reporting requirements to cover emissions from completions and workovers of hydraulically fractured oil wells. Also, the Obama Administration is expected to propose a series of new regulations on the oil and gas industry in 2015, including federal standards limiting methane emissions. These new and proposed rules could result in increased compliance costs for our business.
In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through regional greenhouse gas cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. Such climatic events could have an adverse effect on our financial condition and results of operations.
Endangered Species
The Federal Endangered Species Act, as amended (“ESA”), and analogous state laws restrict activities that could have an adverse effect on threatened or endangered species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our operations may be located in or near areas that are designated as habitat for endangered or threatened species. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to our activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Moreover, as a result of a court settlement the U.S. Fish and Wildlife Service is required to make a determination on listing of numerous species as endangered or threatened under the ESA before the completion of the agency’s 2017 fiscal year. The presence of protected species or the designation of previously unidentified endangered or threatened species could impair our ability to timely complete well drilling and development and could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Employee Health and Safety
We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended, (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, as amended, and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local governmental authorities and citizens.
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Other Laws and Regulations
State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. In addition, there are state statutes, rules and regulations governing conservation matters, including the unitization or pooling of oil and natural gas properties, establishment of maximum rates of production from oil and natural gas wells and the spacing, plugging and abandonment of such wells. Such statutes and regulations may limit the rate at which oil and natural gas could otherwise be produced from our properties and may restrict the number of wells that may be drilled on a particular lease or in a particular field.
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended concerning the Company’s operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and natural gas properties, marketing and midstream activities, and also include those statements accompanied by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “predicts,” “target,” “goal,” “plans,” “objective,” “potential,” “should,” or similar expressions or variations on such expressions that convey the uncertainty of future events or outcomes. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. The Company has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made; the Company undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.
These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risk and uncertainties:
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planned capital expenditures; |
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future drilling activity; |
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our financial condition; |
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business strategy including the our ability to successfully transition to more liquids-focused operations; |
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the market prices of oil and natural gas; |
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volatility in the commodity-futures market; |
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uncertainties about the estimated quantities of oil and natural gas reserves; |
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financial market conditions and availability of capital; |
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production; |
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hedging arrangements; |
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future cash flows and borrowings; |
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litigation matters; |
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pursuit of potential future acquisition opportunities; |
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sources of funding for exploration and development; |
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general economic conditions, either nationally or in the jurisdictions in which we are doing business; |
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legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign and local environmental laws and regulations; |
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the creditworthiness of our financial counterparties and operation partners; |
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the securities, capital or credit markets; |
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our ability to repay our debt; and |
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other factors discussed below and elsewhere in this Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management. |
Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve report. These differences may be material.
The proved oil and natural gas reserve information included in this report are estimates. These estimates are based on reports prepared by NSAI and RSC, our independent reserve engineers, and were calculated using the unweighted average of first-day-of-the-month oil and natural gas prices in 2014. The prices we receive for our production may be lower than those upon which our reserve estimates are based. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:
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historical production from the area compared with production from other similar producing wells; |
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the assumed effects of regulations by governmental agencies; |
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assumptions concerning future oil and natural gas prices; and |
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assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs. |
Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:
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the quantities of oil and natural gas that are ultimately recovered; |
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the production and operating costs incurred; |
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the amount and timing of future development expenditures; and |
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future oil and natural gas sales prices. |
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The discounted future net cash flows included in this document should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the standardized measure of discounted future net cash flows from proved reserves are generally based on 12-month average prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:
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the amount and timing of actual production; |
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supply and demand for oil and natural gas; |
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increases or decreases in consumption; and |
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changes in governmental regulations or taxation. |
In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, and which we use in calculating our PV-10, is not necessarily 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.
Oil and natural gas prices are volatile; a sustained decrease in the price of oil or natural gas would adversely impact our business.
Our success will depend on the market prices of oil and natural gas. These market prices tend to fluctuate significantly in response to factors beyond our control. The prices we receive for our crude oil production are based on global market conditions. The
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general pace of global economic growth, the continued instability in the Middle East and other oil and natural gas producing regions and actions of the Organization of Petroleum Exporting Countries, as well as other economic, political, and environmental factors will continue to affect world supply and prices. Domestic natural gas prices fluctuate significantly in response to numerous factors including U.S. economic conditions, weather patterns, other factors affecting demand such as substitute fuels, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that limit future drilling activities for the industry.
Natural gas and crude oil prices are extremely volatile. For example, spot prices for New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude-oil ranged from a high of $107.95 per barrel to a low of $53.45 per barrel during 2014. Spot prices for NYMEX Henry Hub natural gas ranged from a high of $8.15 per million British thermal units (MMBtu) to a low of $2.99 per MMBtu during 2014. Furthermore, oil prices experienced a significant decline during the fourth quarter of 2014 with NYMEX West Texas Intermediate crude-oil spot prices declining from $91.02 per barrel in October 2014 to $53.45 in December 2014. Crude-oil spot prices continued their decline through January 2015 down to $44.08 per barrel.
Average oil and natural gas prices varied substantially during the past few years. Any actual or anticipated reduction in natural gas and crude oil and prices may further depress the level of exploration, drilling and production activity. We expect that commodity prices will continue to fluctuate significantly in the future.
Changes in commodity prices significantly affect our capital resources, liquidity and expected operating results. Our average realized prices for natural gas increased slightly in 2014 but still remain below average historical prices. These lower prices, coupled with the slow recovery in financial markets that has significantly limited and increased the cost of capital, have compelled most oil and natural gas producers, including us, to reduce the level of exploration, drilling and production activity. This will have a significant effect on our capital resources, liquidity and expected operating results. Any sustained reductions in oil and natural gas prices will directly affect our revenues and can indirectly impact expected production by changing the amount of funds available to us to reinvest in exploration and development activities. Further reductions in oil and natural gas prices could also reduce the quantities of reserves that are commercially recoverable. A reduction in our reserves could have other adverse consequences including a possible downward redetermination of the availability of borrowings under the Second Amended and Restated Credit Agreement between the Company and Wells Fargo and certain lenders dated May 5, 2009, as amended (the “Senior Credit Facility”), which would restrict our liquidity. Additionally, further or continued declines in prices could result in non-cash charges to earnings due to impairment write downs. Any such write down could have a material adverse effect on our results of operations in the period taken.
Our operations are subject to governmental risks that may impact our operations.
Our operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting and changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies or price gathering-rate controls. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our oil and natural gas exploration and production operations are subject to stringent and complex federal, regional, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of permits, including drilling permits, before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several liabilities for the removal or remediation of previously released materials or property contamination. Failure to comply with environmental laws and regulations may result in the assessment of civil and criminal fines and penalties, the revocation of permits or the issuance of injunctions restricting or prohibiting our operations in certain areas. Moreover,
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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, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Changes in environmental laws and regulations occur frequently and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. Any changes in legal requirements related to the protection of the environment could result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, storage, transport, disposal or cleanup requirements. Such changes could also require us to make significant expenditures to attain and maintain compliance, and also have the potential to reduce demand for the oil and gas we produce and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as government reviews of such activity could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales. The process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel and issued guidance in February 2014 related to such activities. Moreover, the EPA has promulgated rules under the federal Clean Air Act requiring operators to use “green completions” to capture the emission of volatile organic compounds from well completion activities involving the use of hydraulic fracturing. The rules also regulate emissions from new or modified compressors, dehydrators, storage tanks, and other production equipment. Also, the EPA issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act in May 2014 seeking comment on potential rules that would require companies to disclose the chemical additives used in their hydraulic fracturing fluids.
In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report expected to be issued for peer review and comment sometime in the first half of 2015. The EPA has also announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities sometime in the first half of 2015. These results of studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Louisiana and Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Moreover, some states and local governments have enacted laws or regulations limiting hydraulic fracturing within their borders or prohibiting the activity altogether. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.
Certain scientific studies have found that emissions of carbon dioxide, methane and other “greenhouse gases” are contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA determined that greenhouse gases present an endangerment to public health and the environment and has issued regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. Recently, the EPA finalized modifications to its GHG reporting rules that would require covered entities to report emissions on an individual GHG basis. In addition, the EPA has proposed a rule that would expand the agency’s reporting requirements to cover emissions from completions and workovers of hydraulically fractured oil wells. Also, the Obama Administration is expected to propose a series of new regulations on the oil and gas industry in 2015,
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including federal standards limiting methane emissions. These new and proposed rules could result in increased compliance costs for our business.
In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through regional greenhouse gas cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. Such climatic events could have an adverse effect on our financial condition and results of operations.
We have incurred losses from operations and may continue to do so in the future.
We incurred losses from operations of $354.8 million, $36.3 million, $63.7 million, $17.1 million and $280.4 million for the years ended December 31, 2014, 2013, 2012, 2011 and 2010, respectively. Our development of and participation of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically acquire and develop oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.
Our future revenues are dependent on the ability to successfully complete drilling activity.
Drilling and exploration are the main methods we utilize to replace our reserves. However, drilling and exploration operations may not result in any increases in reserves for various reasons. Exploration activities involve numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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lack of acceptable prospective acreage; |
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inadequate capital resources; |
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unexpected drilling conditions; |
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pressure or irregularities in formations; |
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equipment failures or accidents; |
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unavailability or high cost of drilling rigs, equipment or labor; |
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reductions in oil and natural gas prices; |
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limitations in the market for oil and natural gas; |
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title problems; |
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compliance with governmental regulations; |
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mechanical difficulties; and |
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risks associated with horizontal drilling. |
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain.
In addition, while lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically, higher oil and natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increased costs for, such drilling equipment, services and personnel. Such shortages could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could adversely affect our ability to increase our reserves and production and reduce our revenues.
21
A sustained depression of oil and natural gas prices can affect our ability to obtain funding, obtain funding on acceptable terms or obtain funding under our current credit facility. This may hinder or prevent us from meeting our future capital needs.
We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on more expensive or otherwise unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.
We have limited experience drilling wells on our Tuscaloosa Marine Shale trend acreage, which has a limited operational history and is subject to more uncertainties than our drilling program in more established formations.
We, along with other operators, have begun drilling wells in the Tuscaloosa Marine Shale trend only recently. Accordingly, we have limited information on which we can determine optimum drilling and completion strategies, or estimate production decline rates or recoverable reserves from drilling on our acreage in this trend. Our drilling plans with respect to the Tuscaloosa Marine Shale trend are flexible and depend on a number of factors, including the extent to which our initial wells in the trend are commercially successful.
A substantial portion of our near term capital investments will be concentrated in the development of the recently acquired acreage in the Tuscaloosa Marine Shale.
We intend to devote a substantial portion of our near term capital expenditures on drilling and completion activity (including facilities and infrastructure) in the Tuscaloosa Marine Shale. The results of these investments may not prove as attractive as we anticipate, and the concentration of such funding and activity in the Tuscaloosa Marine Shale will divert those resources from use to further develop our other properties. There can be no assurance that these investments will generate any specific return on investment.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate, and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.
In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position-limits rule was vacated by the U.S. District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to us for capital expenditures; therefore reducing our ability to execute hedges to reduce risk and protect cash flow. The proposed margin rules are not yet final, and therefore the impact of those provisions on us is uncertain at this time.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, or reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to
22
reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations on us is uncertain.
Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of proposed legislation.
Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives 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, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our common stock.
Our use of oil and natural gas price hedging contracts may limit future revenues from price increases and result in significant fluctuations in our net income.
We use hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases. We hedged approximately 77% (approximately 73% of natural gas production and approximately 82% of oil production) of our total production volumes for the year ended December 31, 2014.
Our results of operations may be negatively impacted by our commodity derivative instruments and fixed price forward sales contracts in the future and these instruments may limit any benefit we would receive from increases in the prices for oil and natural gas. For the year ended December 31, 2014 we received cash receipts to settle our derivative contracts totaling $3.4 million, while we paid $3.8 million to settle our derivative contracts for the year ended December 31, 2013. At December 31, 2014, we had a net asset derivative position of $46.9 million related to our derivative contracts compared to a net asset derivative position of $0.9 million at December 31, 2013. The ultimate settlement amount of these derivative contract positions is dependent on future commodity prices.
We account for our oil and natural gas derivatives using fair value accounting standards. Each derivative is recorded on the balance sheet as an asset or liability at its fair value. Additionally, changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met at the time the derivative contract is executed. We have elected not to apply hedge accounting treatment to our swaps and, as such, all changes in the fair value of these instruments are recognized in earnings. Our fixed price physical contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment.
In the future, we will continue to be exposed to volatility in earnings resulting from changes in the fair value of our derivative instruments. See Note 8-“Derivative Activities” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
Because our operations require significant capital expenditures, we may not have the funds available to replace reserves, maintain production or maintain interests in our properties.
We must make a substantial amount of capital expenditures for the acquisition, exploration and development of oil and natural gas reserves. Historically, we have paid for these expenditures with cash from operating activities, proceeds from debt and equity financings and asset sales. Our revenues or cash flows could be reduced because of lower oil and natural gas prices or for other reasons. If our revenues or cash flows decrease, we may not have the funds available to replace reserves or maintain production at current levels. If this occurs, our production will decline over time. Other sources of financing may not be available to us if our cash flows from operations are not sufficient to fund our capital expenditure requirements. We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on more expensive or otherwise unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to
23
implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. Where we are not the majority owner or operator of an oil and natural gas property, we may have no control over the timing or amount of capital expenditures associated with the particular property. If we cannot fund such capital expenditures, our interests in some properties may be reduced or forfeited.
If we are unable to replace reserves, we may not be able to sustain production at present levels.
Our future success depends largely upon our ability to find, acquire or develop additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. In addition, approximately 54% of our total estimated proved reserves by volume at December 31, 2014, were undeveloped. By their nature, estimates of proved undeveloped reserves and timing of their production are less certain particularly because we may chose not to develop such reserves on anticipated schedules in future adverse oil or natural gas price environments. Recovery of such reserves will require significant capital expenditures and successful drilling operations. The lack of availability of sufficient capital to fund such future operations could materially hinder or delay our replacement of produced reserves. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.
We may incur substantial impairment writedowns.
If management’s estimates of the recoverable proved reserves on a property are revised downward or if oil and natural gas prices decline, we may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to our financial position. Furthermore, any sustained decline in oil and natural gas prices may require us to make further impairments. We review our proved oil and natural gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis.
Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value. For the years ended December 31, 2014 and 2013, we recorded impairments related to oil and natural gas properties of $331.9 million and zero, respectively.
Management’s assumptions used in calculating oil and natural gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property’s fair value. Additionally, as management’s views related to future prices change, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment.
A majority of our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.
Essentially all of our estimated proved reserves at December 31, 2014, and all our production during 2014 were associated with our Louisiana, Texas and Mississippi properties which include the Tuscaloosa Marine Shale, Haynesville Shale and Eagle Ford Shale Trends. Accordingly, if the level of production from these properties substantially declines or is otherwise subject to a disruption in our operations resulting from operational problems, government intervention (including potential regulation or limitation of the use of high pressure fracture stimulation techniques in these formations) or natural disasters, it could have a material adverse effect on our overall production level and our revenue.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. For example, Chesapeake operates certain properties in the Haynesville Shale. We have less ability to influence or control the operation or future development of these non-
24
operated properties or the amount of capital expenditures that we are required to fund with respect to them versus those fields in which we are the operator. Our dependence on the operator and other working interest owners for these projects and our reduced influence or ability to control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.
Our ability to sell natural gas and receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.
We operate primarily in (i) Southwest Mississippi and Southeast Louisiana which includes the Tuscaloosa Marine Shale, (ii) South Texas, which includes the Eagle Ford Shale Trend and (iii) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend. A number of companies are currently operating in the Haynesville Shale and Eagle Ford Shale. If drilling in these areas continues to be successful, the amount of natural gas being produced could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in this region. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for Northwest Louisiana and East Texas may not occur or may be substantially delayed for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our natural gas to interstate pipelines. In such an event, we might have to shut in our wells awaiting a pipeline connection or capacity or sell natural gas production at significantly lower prices than those quoted on New York Mercantile Exchange (NYMEX) or that we currently project, which would adversely affect our results of operations.
A portion of our oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.
Our debt instruments impose restrictions on us that may affect our ability to successfully operate our business.
We have in place a $600 million Senior Credit Facility with a borrowing base of $230 million on which we had $121.0 million drawn on December 31, 2014. The Senior Credit Facility contains customary restrictions, including covenants limiting our ability to incur additional debt, grant liens, make investments, consolidate, merge or acquire other businesses, sell assets, pay dividends and other distributions and enter into transactions with affiliates. We also are required to meet specified financial ratios under the terms of our Senior Credit Facility. As of December 31, 2014, we were in compliance with all the financial covenants of our Senior Credit Facility. These restrictions may make it difficult for us to successfully execute our business strategy or to compete in our industry with companies not similarly restricted. The Senior Credit Facility matures on February 24, 2017. Any replacement credit facility may have more restrictive covenants or provide us with less borrowing capacity.
We may be unable to identify liabilities associated with the properties that we acquire or obtain protection from sellers against them.
The acquisition of properties requires us to assess a number of factors, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well, facility or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion or subsurface groundwater contamination, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities relating to the acquired assets and indemnities are unlikely to cover liabilities relating to the time periods after closing. We may be required to assume any risk relating to the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. The incurrence of an unexpected liability could have a material adverse effect on our financial position and results of operations.
Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could materially adversely affect our financial condition, results of operations and cash flows.
Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. Revenues from the largest of these sources as a percent of oil and natural gas revenues for the year ended December 31, 2014, 2013 and 2012 were 57%, 71% and 49%, respectively. Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be
25
disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our financial condition, results of operations and cash flows. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.
Customer credit risks could result in losses.
Our exposure to non-payment or non-performance by our customers and counterparties presents a credit risk. Generally, non-payment or non-performance results from a customer’s or counterparty’s inability to satisfy obligations. We monitor the creditworthiness of our customers and counterparties and established credit limits according to our credit policies and guidelines, but cannot assure that any losses will be consistent with our expectations. Furthermore, the concentration of our customers in the energy industry may impact our overall exposure to credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2014, 2013 and 2012 are as follows:
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014
|
|
|
2013
|
|
|
2012
|
|
|||
|
BP Energy Company |
|
|
46% |
|
|
|
64% |
|
|
|
34% |
|
|
Genesis Crude Oil LP |
|
|
11% |
|
|
|
7% |
|
|
|
— |
|
|
Flint Hill Resources, LLC |
|
|
— |
|
|
|
— |
|
|
|
15% |
|
Competition in the oil and natural gas industry is intense, and we are smaller and have a more limited operating history than some of our competitors.
We compete with major and independent oil and natural gas companies for property acquisitions. We also compete for the equipment and labor required to operate and to develop these properties. Some of our competitors have substantially greater financial and other resources than us. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for oil and natural gas properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Our success depends on our management team and other key personnel, the loss of any of whom could disrupt our business operations.
Our success will depend on our ability to retain and attract experienced engineers, geoscientists and other professional staff. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.
The oil and natural gas exploration and production business involves many uncertainties, economic risks and operating risks that can prevent us from realizing profits and can cause substantial losses.
The nature of the oil and natural gas exploration and production business involves certain operating hazards such as:
|
· |
well blowouts; |
|
· |
cratering; |
|
· |
explosions; |
|
· |
uncontrollable flows of oil, natural gas, brine or well fluids; |
|
· |
fires; |
|
· |
formations with abnormal pressures; |
|
· |
shortages of, or delays in, obtaining water for hydraulic fracturing operations; |
|
· |
environmental hazards such as crude oil spills; |
26
|
· |
natural gas leaks; |
|
· |
pipeline and tank ruptures; |
|
· |
unauthorized discharges of brine, well stimulation and completion fluids or toxic gases into the environment; |
|
· |
encountering naturally occurring radioactive materials; |
|
· |
other pollution; and |
|
· |
other hazards and risks. |
Any of these operating hazards could result in substantial losses to us. As a result, substantial liabilities to third parties or governmental entities may be incurred. The payment of these amounts could reduce or eliminate the funds available for exploration, development or acquisitions. These reductions in funds could result in a loss of our properties. Additionally, some of our oil and natural gas operations are located in areas that are subject to weather disturbances such as hurricanes. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production.
We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.
We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:
|
· |
personal injury; |
|
· |
bodily injury; |
|
· |
third party property damage; |
|
· |
medical expenses; |
|
· |
legal defense costs; |
|
· |
pollution in some cases; |
|
· |
well blowouts in some cases; and |
|
· |
workers compensation. |
As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover every claim made against us in the future. A loss in connection with our oil and natural gas properties could have a materially adverse effect on our financial position and results of operations to the extent that the insurance coverage provided under our policies cover only a portion of any such loss.
None.
A discussion of our current legal proceedings is set forth in Note 9—“Commitments and Contingencies” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
Not Applicable.
27
PART II
|
Item 5. |
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Market Price of Our Common Stock
Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “GDP”.
At February 26, 2015, the number of holders of record of our common stock was 1,087 and 45,109,912 shares were outstanding. High and low sales prices for our common stock for each quarter during 2014 and 2013 as reported on the NYSE were as follows:
|
|
|
2014 |
|
|
2013 |
|
||||||||||
|
|
|
High |
|
|
Low |
|
|
High |
|
|
Low |
|
||||
|
First Quarter |
|
$ |
18.81 |
|
|
$ |
11.80 |
|
|
$ |
16.18 |
|
|
$ |
8.68 |
|
|
Second Quarter |
|
|
30.52 |
|
|
|
15.36 |
|
|
|
16.00 |
|
|
|
11.16 |
|
|
Third Quarter |
|
|
27.95 |
|
|
|
14.09 |
|
|
|
27.65 |
|
|
|
12.18 |
|
|
Fourth Quarter |
|
|
14.85 |
|
|
|
2.96 |
|
|
|
28.55 |
|
|
|
15.66 |
|
Dividends
We have neither declared nor paid any cash dividends on our common stock and do not anticipate declaring any dividends in the foreseeable future. We expect to retain our cash for the operation and expansion of our business, including exploration, development and production activities. In addition, our senior bank credit facility contains restrictions on the payment of dividends to the holders of common stock. For additional information, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.
Issuer Repurchases of Equity Securities
We made no open market repurchases of our common stock for the year ended December 31, 2014.
For information on securities authorized for issuance under our equity compensation plans, see Item 12. “Security Ownership of Certain Beneficial Owners and Management”.
Unregistered Sales of Equity Securities
None that have not been previously reported by us on a Current Report on Form 8-K.
28
Performance
The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the company specifically incorporates it by reference into such filing.
The following graph compares the cumulative five-year total return to stockholders on our common stock relative to the cumulative total returns of the S&P 500 Index and the Russell 2000 Index. An investment of $100 is assumed to have been made in our common stock and the indexes on December 31, 2009 and its relative performance is tracked through December 31, 2014.
29
The following table sets forth our selected financial data and other operating information. The selected consolidated financial data in the table are derived from our consolidated financial statements. This data should be read in conjunction with the consolidated financial statements, related notes and other financial information included herein.
|
|
|
Summary Financial Information |
|
|||||||||||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
|||||
|
|
|
(In thousands, except per share amounts) |
|
|||||||||||||||||
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
208,544 |
|
|
$ |
202,557 |
|
|
$ |
180,543 |
|
|
$ |
200,456 |
|
|
$ |
148,031 |
|
|
Other |
|
|
9 |
|
|
|
738 |
|
|
|
302 |
|
|
|
613 |
|
|
|
302 |
|
|
|
|
|
208,553 |
|
|
|
203,295 |
|
|
|
180,845 |
|
|
|
201,069 |
|
|
|
148,333 |
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
29,525 |
|
|
|
27,293 |
|
|
|
25,938 |
|
|
|
21,490 |
|
|
|
26,306 |
|
|
Production and other taxes |
|
|
9,905 |
|
|
|
9,812 |
|
|
|
8,115 |
|
|
|
5,450 |
|
|
|
3,627 |
|
|
Transportation and processing |
|
|
9,070 |
|
|
|
10,498 |
|
|
|
13,900 |
|
|
|
12,974 |
|
|
|
9,856 |
|
|
Depreciation, depletion and amortization |
|
|
135,716 |
|
|
|
135,357 |
|
|
|
141,222 |
|
|
|
131,811 |
|
|
|
105,913 |
|
|
Exploration |
|
|
6,206 |
|
|
|
22,774 |
|
|
|
23,122 |
|
|
|
8,289 |
|
|
|
10,152 |
|
|
Impairment |
|
|
331,931 |
|
|
|
— |
|
|
|
47,818 |
|
|
|
8,111 |
|
|
|
234,887 |
|
|
General and administrative |
|
|
33,728 |
|
|
|
34,069 |
|
|
|
28,930 |
|
|
|
29,799 |
|
|
|
30,918 |
|
|
Loss (gain) on sale of assets |
|
|
3,499 |
|
|
|
(107 |
) |
|
|
(44,606 |
) |
|
|
(236 |
) |
|
|
2,824 |
|
|
Other |
|
|
3,793 |
|
|
|
(91 |
) |
|
|
91 |
|
|
|
448 |
|
|
|
4,268 |
|
|
|
|
|
563,373 |
|
|
|
239,605 |
|
|
|
244,530 |
|
|
|
218,136 |
|
|
|
428,751 |
|
|
Operating loss |
|
|
(354,820 |
) |
|
|
(36,310 |
) |
|
|
(63,685 |
) |
|
|
(17,067 |
) |
|
|
(280,418 |
) |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(47,829 |
) |
|
|
(51,187 |
) |
|
|
(52,403 |
) |
|
|
(49,351 |
) |
|
|
(37,179 |
) |
|
Interest income and other |
|
|
90 |
|
|
|
101 |
|
|
|
4 |
|
|
|
59 |
|
|
|
117 |
|
|
Gain (loss) on derivatives not designated as hedges |
|
|
49,423 |
|
|
|
(702 |
) |
|
|
31,882 |
|
|
|
34,539 |
|
|
|
55,275 |
|
|
Gain (loss) on extinguishment of debt |
|
|
— |
|
|
|
(7,088 |
) |
|
|
— |
|
|
|
62 |
|
|
|
— |
|
|
|
|
|
1,684 |
|
|
|
(58,876 |
) |
|
|
(20,517 |
) |
|
|
(14,691 |
) |
|
|
18,213 |
|
|
Loss before income taxes |
|
|
(353,136 |
) |
|
|
(95,186 |
) |
|
|
(84,202 |
) |
|
|
(31,758 |
) |
|
|
(262,205 |
) |
|
Income tax benefit |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
85 |
|
|
Net loss |
|
|
(353,136 |
) |
|
|
(95,186 |
) |
|
|
(84,202 |
) |
|
|
(31,758 |
) |
|
|
(262,120 |
) |
|
Preferred stock dividends |
|
|
29,722 |
|
|
|
18,604 |
|
|
|
6,047 |
|
|
|
6,047 |
|
|
|
6,047 |
|
|
Net loss applicable to common stock |
|
$ |
(382,858 |
) |
|
$ |
(113,790 |
) |
|
$ |
(90,249 |
) |
|
$ |
(37,805 |
) |
|
$ |
(268,167 |
) |
|
PER COMMON SHARE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss applicable to common stock—basic |
|
$ |
(8.62 |
) |
|
$ |
(2.99 |
) |
|
$ |
(2.48 |
) |
|
$ |
(1.05 |
) |
|
$ |
(7.47 |
) |
|
Net loss applicable to common stock—diluted |
|
$ |
(8.62 |
) |
|
$ |
(2.99 |
) |
|
$ |
(2.48 |
) |
|
$ |
(1.05 |
) |
|
$ |
(7.47 |
) |
|
Weighted average common shares outstanding—basic |
|
|
44,402 |
|
|
|
38,098 |
|
|
|
36,390 |
|
|
|
36,124 |
|
|
|
35,921 |
|
|
Weighted average common shares outstanding—diluted |
|
|
44,402 |
|
|
|
38,098 |
|
|
|
36,390 |
|
|
|
36,124 |
|
|
|
35,921 |
|
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
722,138 |
|
|
$ |
974,213 |
|
|
$ |
768,385 |
|
|
$ |
862,103 |
|
|
$ |
664,577 |
|
|
Total long-term debt |
|
|
568,625 |
|
|
|
435,866 |
|
|
|
568,671 |
|
|
|
566,126 |
|
|
|
179,171 |
|
|
Stockholders’ equity |
|
|
(15,774 |
) |
|
|
356,523 |
|
|
|
60,245 |
|
|
|
143,700 |
|
|
|
183,972 |
|
30
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Annual Report on Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A.
Overview
We are an independent oil and natural gas company engaged in the exploration, development and production of properties primarily in (i) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale (“TMS”), (ii) South Texas, which includes the Eagle Ford Shale Trend, and (iii) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend.
We seek to increase shareholder value by growing our oil and natural gas reserves, production revenues and operating cash flow. In our opinion, on a long term basis, growth in oil and natural gas reserves and production on a cost-effective basis are the most important indicators of performance success for an independent oil and natural gas company.
Management strives to increase our oil and natural gas reserves, production and cash flow through exploration and development activities. We develop an annual capital expenditure budget, which is reviewed and approved by our board of directors on a quarterly basis and revised throughout the year as circumstances warrant. We take into consideration our projected operating cash flow and externally available sources of financing, such as bank debt, asset divestures, issuance of debt and equity securities and strategic joint-ventures, when establishing our capital expenditure budget.
We place primary emphasis on our cash flow from operating activities (“operating cash flow”) in managing our business. Management considers operating cash flow a more important indicator of our financial success than other traditional performance measures such as net income because operating cash flow considers only the cash expenses incurred during the period and excludes the non-cash impact of unrealized hedging gains (losses), non-cash general and administrative expenses and impairments.
Our revenues and operating cash flow depend on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and natural gas. Such pricing factors are largely beyond our control; however, we employ commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow.
Business Strategy
Our business strategy is to provide long-term growth in reserves and cash flow on a cost-effective basis. We focus on maximizing our return on capital employed and adding reserve value through the timely development of our TMS, Eagle Ford Shale Trend and Haynesville Shale Trend acreage. We regularly evaluate possible acquisitions of prospective acreage and oil and natural gas drilling opportunities.
Several of the key elements of our business strategy are the following:
|
· |
Develop our core position in the TMS. We seek to maximize the value of our existing assets by developing and exploiting our properties with the lowest risk and the highest potential rate of return. In the current commodity price environment, we intend to focus the development of our core acreage position through drilling in the TMS. |
|
· |
Maintain oil production. During the past three years, we have concentrated on increasing our crude oil production and reserves by investing and drilling in the TMS and Eagle Ford Shale Trend. However, we intend to keep oil production relatively flat over the next year as we monitor the crude oil markets, return to growth when markets improve and focus drilling in the TMS. We will continue to evaluate our capital allocation to oil and natural gas drilling as market conditions dictate. |
|
· |
Maintain our acreage position in shale plays. As of December 31, 2014, we held approximately 327,000 net acres in the TMS in Southeastern Louisiana and Southwestern Mississippi. We continue to concentrate our efforts in areas where we can apply our technical expertise and where we have significant operational control or experience. To leverage our extensive regional knowledge base, we seek to acquire leasehold acreage with significant drilling potential in areas that exhibit characteristics similar to our existing properties. We continually strive to rationalize our portfolio of properties by selling non-core properties in an effort to redeploy capital to exploitation, development and exploration projects that offer a potentially higher overall return. |
31
|
· |
Focus on maximizing cash flow margins and conserving capital. We intend to maximize operating cash flow by focusing on higher-margin oil development in the TMS and working with service providers to reduce costs in the TMS. In the current commodity price environment, our TMS assets offer rates of return on capital invested and cash flow margins more favorable than our natural gas assets. In January 2015, we announced a reduced capital expenditure budget of $90 to $110 million for 2015. |
|
· |
Enhance financial flexibility. As of December 31, 2014, we had a borrowing base of $230 million under our $600 million Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”), on which we had $121 million drawn. On February 26, 2015 we entered into a definitive agreement to issue $100 million of second lien senior secured notes, which will be used to pay down the amount drawn on our Senior Credit Facility. Our borrowing base was reduced to $200 million on February 26, 2015 and will be further reduced to $150 million on the earlier of April 1, 2015 or the funding of the $100 million second lien senior secured notes. We have historically funded growth through operating cash flow, debt, equity and equity-linked security issuances, divestments of non-core assets and entering into strategic joint ventures. In addition, we may divest our Eagle Ford Shale assets if market conditions improve and will continue to seek a joint venture partner to share in the cost to develop our acreage in the TMS. We also actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, including fixed price swaps, swaptions and costless collars. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy. |
2014 Highlights
|
· |
Our annual oil production increased to 40% of our equivalent production in 2014 from 29% in 2013 and we achieved average daily oil production volume growth of 26% for the year, with production volumes growing from an average of 3,665 barrels of oil per day in 2013 to 4,635 barrels of oil per day in 2014. |
|
· |
We ended the year with estimated proved reserves of approximately 274 Bcfe (approximately 105 Bcf of natural gas, 1 MMBbls of NGL and 27 MMBbls of oil and condensate), with a PV-10 of $651 million and a standardized measure of $644.7 million, approximately 46% of which is proved developed. |
|
· |
We conducted drilling operations on 29 gross (21 net) wells in 2014, including 22 gross (16 net) wells in the TMS and 6 gross (4 net) Eagle Ford Shale Trend wells in South Texas. We added 23 gross (16 net) wells to production in 2014, of which 17 gross (12 net) were in the TMS, and 6 gross (4 net) were in the Eagle Ford Shale Trend. |
|
· |
Our crude oil reserves grew to 59% of our total reserves as of December 31, 2014 compared to 19% for the year ended 2013. Our PV-10 also grew 38% to $651 million at December 31, 2014 compared to $472 million at December 31, 2013. |
Tuscaloosa Marine Shale Trend
We held approximately 461,000 gross (327,000 net) acres in the TMS as of December 31, 2014. Our acreage is located in Southeastern Louisiana and Southwestern Mississippi. Since December 31, 2013, we have added approximately 46,000 gross (21,000 net) acres in the trend.
During 2014, we conducted drilling operations on approximately 22 gross (16 net), TMS wells. As of December 31, 2014, we had 4 gross (3.5 net) TMS wells drilled and waiting on completion. Our net production volumes from our TMS wells represented approximately 18% of our total equivalent production on a Mcfe basis and approximately 44% of our total oil production for the year ended December 31, 2014. During 2014, we spent $263.0 million in the Tuscaloosa Marine Shale Trend, which included $22.8 million for leasehold costs. We plan on spending approximately 91% to 93% of our total 2015 capital budget in the TMS.
Eagle Ford Shale Trend
We entered into the Eagle Ford Shale Trend in April 2010, with our leasehold position located in La Salle and Frio counties, Texas. We held approximately 44,000 gross (30,000 net) acres as of December 31, 2014, all of which are either producing from or prospective for the Eagle Ford Shale Trend. During 2014, we conducted drilling operations on approximately 6 gross (4 net) Eagle Ford Shale Trend wells. During the year ended December 31, 2014, we spent $52.5 million on drilling and completion, leasehold and infrastructure capital expenditures in the Eagle Ford Shale Trend. Our net production volumes from our Eagle Ford Shale Trend wells represented approximately 27% of our total equivalent production on a Mcfe basis and approximately 55% of our total oil production for 2014.
32
Haynesville Shale Trend
Our relatively low risk development acreage in this trend is primarily centered in and around Angelina and Nacogdoches counties, Texas and DeSoto and Caddo parishes, Louisiana. We hold approximately 67,000 gross (37,000 net) acres as of December 31, 2014 producing from or prospective for the Haynesville Shale. Our net production volumes from our Haynesville Shale wells aggregated approximately 41% of our total oil and natural gas production for the year.
Core Haynesville Shale
Our core Haynesville Shale acreage is primarily concentrated in the Bethany-Longstreet and Greenwood-Waskom fields in Caddo and DeSoto Parishes in Northwest Louisiana. Our core Haynesville Shale drilling activity includes both operated and non-operated drilling in and around our core acreage positions in Northwest Louisiana. We currently hold approximately 32,000 gross (14,000 net) acres as of December 31, 2014.
Shelby Trough / Angelina River Trend
We operate all of our acreage in this area, which is primarily located in Nacogdoches, Angelina and Shelby counties, Texas. We held approximately 29,000 gross (22,000 net) acres as of December 31, 2014.
Results of Operations
For the year ended December 31, 2014, we reported net loss applicable to common stock of $382.9 million, or $8.62 per share (basic and diluted), on operating revenues of $208.5 million. This compares to net loss applicable to common stock of $113.8 million, or $2.99 per share (basic and diluted), for the year ended December 31, 2013 and net loss applicable to common stock of $90.2 million, or $2.48 per share (basic and diluted), for the year ended December 31, 2012. The largest change in net loss from 2013 to 2014 is the $331.9 million impairment expense recorded in 2014.
The following table reflects our summary operating information for the periods presented in thousands except for price and volume data. Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results.
|
|
|
Year End December 31, |
|
|
Year End December 31, |
|
||||||||||||||||||||||||||
|
Summary Operating Information: |
|
2014 |
|
|
2013 |
|
|
Variance |
|
|
2013 |
|
|
2012 |
|
|
Variance |
|
||||||||||||||
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
$ |
56,140 |
|
|
$ |
66,180 |
|
|
$ |
(10,040 |
) |
|
|
(15 |
%) |
|
$ |
66,180 |
|
|
$ |
71,136 |
|
|
$ |
(4,956 |
) |
|
|
(7 |
%) |
|
Oil and condensate |
|
|
152,404 |
|
|
|
136,377 |
|
|
|
16,027 |
|
|
|
12 |
% |
|
|
136,377 |
|
|
|
109,407 |
|
|
|
26,970 |
|
|
|
25 |
% |
|
Natural gas, oil and condensate |
|
|
208,544 |
|
|
|
202,557 |
|
|
|
5,987 |
|
|
|
3 |
% |
|
|
202,557 |
|
|
|
180,543 |
|
|
|
22,014 |
|
|
|
12 |
% |
|
Operating revenues |
|
|
208,553 |
|
|
|
203,295 |
|
|
|
5,258 |
|
|
|
3 |
% |
|
|
203,295 |
|
|
|
180,845 |
|
|
|
22,450 |
|
|
|
12 |
% |
|
Operating expenses |
|
|
563,373 |
|
|
|
239,605 |
|
|
|
323,768 |
|
|
|
135 |
% |
|
|
239,605 |
|
|
|
244,530 |
|
|
|
(4,925 |
) |
|
|
(2 |
%) |
|
Operating loss |
|
|
(354,820 |
) |
|
|
(36,310 |
) |
|
|
(318,510 |
) |
|
|
877 |
% |
|
|
(36,310 |
) |
|
|
(63,685 |
) |
|
|
27,375 |
|
|
|
(43 |
%) |
|
Net loss applicable to common stock |
|
|
(382,858 |
) |
|
|
(113,790 |
) |
|
|
(269,068 |
) |
|
|
236 |
% |
|
|
(113,790 |
) |
|
|
(90,249 |
) |
|
|
(23,541 |
) |
|
|
26 |
% |
|
Net Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mmcf) |
|
|
14,980 |
|
|
|
19,760 |
|
|
|
(4,780 |
) |
|
|
(24 |
%) |
|
|
19,760 |
|
|
|
24,844 |
|
|
|
(5,084 |
) |
|
|
(20 |
%) |
|
Oil and condensate (MBbls) |
|
|
1,692 |
|
|
|
1,338 |
|
|
|
354 |
|
|
|
26 |
% |
|
|
1,338 |
|
|
|
1,095 |
|
|
|
243 |
|
|
|
22 |
% |
|
Total (Mmcfe) |
|
|
25,131 |
|
|
|
27,785 |
|
|
|
(2,654 |
) |
|
|
(10 |
%) |
|
|
27,785 |
|
|
|
31,415 |
|
|
|
(3,630 |
) |
|
|
(12 |
%) |
|
Average daily production (Mcfe/d) |
|
|
68,853 |
|
|
|
76,124 |
|
|
|
(7,271 |
) |
|
|
(10 |
%) |
|
|
76,124 |
|
|
|
85,832 |
|
|
|
(9,708 |
) |
|
|
(11 |
%) |
|
Average Realized Sales Price Per Unit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
|
$ |
3.75 |
|
|
$ |
3.35 |
|
|
|
0.40 |
|
|
|
12 |
% |
|
$ |
3.35 |
|
|
$ |
2.86 |
|
|
$ |
0.49 |
|
|
|
17 |
% |
|
Natural gas (per Mcf) including the effect of realized gains/losses on derivatives |
|
|
4.03 |
|
|
|
3.38 |
|
|
|
0.65 |
|
|
|
19 |
% |
|
|
3.38 |
|
|
|
5.50 |
|
|
|
(2.12 |
) |
|
|
(39 |
%) |
|
Oil and condensate (per Bbl) |
|
|
90.08 |
|
|
|
101.96 |
|
|
|
(11.88 |
) |
|
|
(12 |
%) |
|
|
101.96 |
|
|
|
99.91 |
|
|
|
2.05 |
|
|
|
2 |
% |
|
Oil and condensate (per Bbl) including the effect of realized gains/losses on derivatives |
|
|
89.61 |
|
|
|
98.70 |
|
|
|
(9.09 |
) |
|
|
(9 |
%) |
|
|
98.70 |
|
|
|
106.98 |
|
|
|
(8.28 |
) |
|
|
(8 |
%) |
|
Average realized price (per Mcfe) |
|
|
8.30 |
|
|
|
7.29 |
|
|
|
1.01 |
|
|
|
14 |
% |
|
|
7.29 |
|
|
|
5.75 |
|
|
|
1.54 |
|
|
|
27 |
% |
33
Oil and Natural Gas Revenue
Our natural gas, oil and condensate revenues increased in 2014 compared to 2013 reflecting an increase in oil and condensate production and an increase in our average realized sales prices for natural gas, partially offset by a decline in our average realized sales prices for oil and condensate and a reduction in natural gas production. The increases in oil production and natural gas realized sales prices compared to 2013 contributed approximately $39.8 million to the increase in natural gas, oil and condensate revenue, which was partially offset by $33.8 million due to decreased natural gas production and a decline in our average realized sales prices for oil and condensate compared to 2013.
The difference between our average realized prices inclusive of net cash derivative settlements in the years ended December 31, 2014 and 2013 relates to our oil and natural gas swap contracts. During 2014, we had derivative contracts covering 30,000 MMBtus per day at an average floor price of $4.76 per MMBtu and during the full year of 2013 we had derivative contracts covering 10,000 MMBtus per day at a floor price of $4.18 per MMBtu. During 2014, we had an average of 3,800 Bbls per day hedged at an average fixed price of $93.65 per Bbl. During 2013, we had 3,626 Bbls per day hedged at an average fixed price of $94.65 per Bbl.
Natural gas, oil and condensate revenues increased in 2013 compared to 2012 reflecting an increase in oil and condensate production and an increase in our average realized sales prices, not including the effects of derivatives, partially offset by a decline in natural gas production. The increases in oil production and realized sales prices compared to 2012 contributed approximately $39.1 million to the increase in natural gas, oil and condensate revenue, which were partially offset by $17.1 million due to decreased natural gas production compared to 2012. During 2013, we focused on increasing oil production, which we were able to sell at a more favorable relative price than natural gas. In 2013, 67% of our natural gas, oil and condensate revenue was attributable to oil compared to 61% in 2012.
The difference between our average realized prices inclusive of net cash derivative settlements in the years ended December 31, 2013 and 2012 relates to our oil and natural gas swap contracts. During 2013, we had derivative contracts covering 10,000 MMBtus per day only for the fourth quarter of 2013 at a floor price of $4.18 per MMBtu and during the full year of 2012 we had derivative contracts covering 60,000 MMBtus per day at a floor price of $5.78 per MMBtu. During 2013, we had derivative contracts covering an average of 3,626 Bbls per day at an average fixed price of $94.65 per Bbl. During 2012, we had derivative contracts covering 3,500 Bbls per day at an average fixed price of $100.12 per Bbl.
Operating Expenses
Our operating expenses in 2014 increased by $323.8 million primarily as a result of recognizing $331.9 million of asset impairment expense and a $3.5 million loss on the sale of assets. When excluding these items from the operating expenses in both 2014 and 2013, the adjusted operating expense of $227.9 million in 2014 decreased 5%, or $11.7 million, from the adjusted operating expense of $239.7 million in 2013. This decrease in operating expense is driven by decreased exploration expense.
Our operating expenses in 2013 includes $4.4 million of dry hole expense and lease expirations of $11.5 million. When eliminating these items from the operating expenses in both 2013 and 2012, the adjusted operating expense of $223.7 million in 2013 decreased 3%, or $8.0 million, from adjusted operating expense of $231.7 million in 2012. This decrease in operating expenses is driven by decreased depreciation, depletion and amortization (“DD&A”) expense.
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
||||||||||||||||||||||||||
|
(in thousands) |
|
2014 |
|
|
2013 |
|
|
Variance |
|
|
2013 |
|
|
2012 |
|
|
Variance |
|
||||||||||||||
|
Lease operating expenses |
|
$ |
29,525 |
|
|
$ |
27,293 |
|
|
$ |
2,232 |
|
|
|
8 |
% |
|
$ |
27,293 |
|
|
$ |
25,938 |
|
|
$ |
1,355 |
|
|
|
5 |
% |
|
Production and other taxes |
|
|
9,905 |
|
|
|
9,812 |
|
|
|
93 |
|
|
|
1 |
% |
|
|
9,812 |
|
|
|
8,115 |
|
|
|
1,697 |
|
|
|
21 |
% |
|
Transportation and processing |
|
|
9,070 |
|
|
|
10,498 |
|
|
|
(1,428 |
) |
|
|
(14 |
)% |
|
|
10,498 |
|
|
|
13,900 |
|
|
|
(3,402 |
) |
|
|
(24 |
%) |
|
Exploration |
|
|
6,206 |
|
|
|
22,774 |
|
|
|
(16,568 |
) |
|
|
(73 |
)% |
|
|
22,774 |
|
|
|
23,122 |
|
|
|
(348 |
) |
|
|
(2 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
||||||||||||||||||||||||||
|
Per Mcfe |
|
2014 |
|
|
2013 |
|
|
Variance |
|
|
2013 |
|
|
2012 |
|
|
Variance |
|
||||||||||||||
|
Lease operating expenses |
|
$ |
1.17 |
|
|
$ |
0.98 |
|
|
$ |
0.19 |
|
|
|
20 |
% |
|
$ |
0.98 |
|
|
$ |
0.83 |
|
|
$ |
0.15 |
|
|
|
18 |
% |
|
Production and other taxes |
|
|
0.39 |
|
|
|
0.35 |
|
|
|
0.04 |
|
|
|
11 |
% |
|
|
0.35 |
|
|
|
0.26 |
|
|
|
0.09 |
|
|
|
35 |
% |
|
Transportation and processing |
|
|
0.36 |
|
|
|
0.38 |
|
|
|
(0.02 |
) |
|
|
(5 |
)% |
|
|
0.38 |
|
|
|
0.44 |
|
|
|
(0.06 |
) |
|
|
(14 |
%) |
|
Exploration |
|
|
0.25 |
|
|
|
0.82 |
|
|
|
(0.57 |
) |
|
|
(70 |
)% |
|
|
0.82 |
|
|
|
0.74 |
|
|
|
0.08 |
|
|
|
11 |
% |
34
Lease Operating Expense
Our lease operating expense (“LOE”) during 2014 included an expense of $4.3 million in workover costs which added $0.17 per Mcfe to LOE. Our LOE during 2013 included $6.0 million in workover costs which added $0.22 per Mcfe to LOE. LOE excluding workover expense increased in 2014 compared to 2013. The majority of the increase, or $3.7 million, was associated with the wells we purchased in August 2013 and wells we brought online in the TMS. Our LOE will generally trend higher as we add more oil wells to our well count which carry higher operating costs than natural gas wells. Oil contributed approximately 40% to our equivalent production volumes in 2014 compared to 29% in 2013.
Our LOE during 2013 included an expense of $6.0 million in workover costs, which added $0.22 per Mcfe to LOE. Our LOE during 2012 included $4.3 million in workover costs, which added $0.13 per Mcfe to LOE. LOE excluding workover expense decreased in 2013 compared to 2012. The absence of $2.1 million in LOE for the South Henderson Field, which we sold in late September 2012, was partially offset by increased expense related to oil production. Our LOE will generally trend higher as we add more oil wells to our well count, which carry higher operating costs than natural gas wells. Oil contributed 29% to our equivalent production volumes in 2013 compared to 21% in 2012.
Production and Other Taxes
Our production and other taxes for the year 2014 included production tax of $6.2 million and ad valorem tax of $3.7 million. Production and other taxes increased slightly in 2014 due to an increase in ad valorem taxes associated with new TMS and Eagle Ford Shale Trend wells offset by lower production taxes. The decrease in production tax for the year ended 2014 is associated with lower oil production from our Eagle Ford Shale wells and lower tax rates on the TMS wells drilled in the state of Mississippi after July 1, 2013. The State of Mississippi has enacted an exemption from the existing 6% severance tax for horizontal wells drilled after July 1, 2013 with production commencing before July 1, 2018, which will be partially offset by a 1.3% local severance tax on such wells. The exemption is applicable until the earlier of (i) 30 months from the date of first sale of production or (ii) until payout of the well cost is achieved. The State of Louisiana has also enacted an exemption from the existing 12.5% severance tax for horizontal wells with production commencing after July 31, 1994. The exemption is applicable until the earlier of (i) 24 months from the date of first sale of production or (ii) until payout of the well cost is achieved. The net revenues from our wells drilled in our TMS acreage in Southwestern Mississippi and Southeast Louisiana have been favorably impacted by these exemptions.
Our production and other taxes for the year 2013 included production tax of $7.4 million and ad valorem tax of $2.4 million. We did not earn any tax credits in 2013 attributed to Tight Gas Sands (“TGS”) credits for our wells in the State of Texas. Production and other taxes for the year 2012 include production tax of $5.6 million and ad valorem tax of $2.5 million. Production tax in 2012 is net of $1.6 million of tax credits attributed to TGS credits.
Transportation and Processing
Transportation and processing expense decreased in 2014 compared to 2013 due to lower operated natural gas production in 2014, as our natural gas production incurs substantially all of our transportation and processing cost.
The sale of the South Henderson Field in September 2012, which contributed $2.3 million of expense in 2012, and overall lower natural gas production decreased our transportation and processing expense in 2013 compared to 2012.
Exploration
The decrease in exploration expenses in 2014 compared to 2013 was attributable primarily to lower lease amortization costs primarily associated with expiring leases in our Eagle Ford Shale Trend acreage of $10.2 million, lower seismic costs of $1.5 million and lower dry hole costs of $4.4 million.
35
Exploration expense decreased slightly in 2013 from 2012. Dry hole cost declined $8.4 million as we suspended operations on the Denkmann 33H-1 and expensed $12.8 million of the well cost in 2012. We opted not to drill a new well utilizing the existing well bore and expensed the remaining well costs of $4.4 million in 2013. Lease amortization in 2013 increased $7.8 million from $5.9 million in 2012 to $13.7 million in 2013, which mostly offsets the decrease in dry hole cost. Lease amortization in 2013 included lease expiration expense. As part of our ongoing review of capital allocation, we elected not to renew certain expiring leases in non-core Eagle Ford Shale Trend acreage resulting in $11.1 million lease expiration expense.
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
||||||||||||||||||||||||||
|
(in thousands) |
|
2014 |
|
|
2013 |
|
|
Variance |
|
|
2013 |
|
|
2012 |
|
|
Variance |
|
||||||||||||||
|
Depreciation, depletion & amortization |
|
$ |
135,716 |
|
|
$ |
135,357 |
|
|
$ |
359 |
|
|
|
0 |
% |
|
$ |
135,357 |
|
|
$ |
141,222 |
|
|
$ |
(5,865 |
) |
|
|
(4 |
%) |
|
Impairment |
|
|
331,931 |
|
|
|
— |
|
|
|
331,931 |
|
|
|
100 |
% |
|
|
— |
|
|
|
47,818 |
|
|
|
(47,818 |
) |
|
|
(100 |
%) |
|
General & administrative |
|
|
33,728 |
|
|
|
34,069 |
|
|
|
(341 |
) |
|
|
(1 |
)% |
|
|
34,069 |
|
|
|
28,930 |
|
|
|
5,139 |
|
|
|
18 |
% |
|
(Gain) loss on sale of assets |
|
|
3,499 |
|
|
|
(107 |
) |
|
|
3,606 |
|
|
NM |
|
|
|
(107 |
) |
|
|
(44,606 |
) |
|
|
44,499 |
|
|
|
(100 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
||||||||||||||||||||||||||
|
Per Mcfe |
|
2014 |
|
|
2013 |
|
|
Variance |
|
|
2013 |
|
|
2012 |
|
|
Variance |
|
||||||||||||||
|
Depreciation, depletion & amortization |
|
$ |
5.40 |
|
|
$ |
4.87 |
|
|
$ |
0.53 |
|
|
|
11 |
% |
|
$ |
4.87 |
|
|
$ |
4.50 |
|
|
$ |
0.37 |
|
|
|
8 |
% |
|
Impairment |
|
$ |
13.21 |
|
|
|
— |
|
|
$ |
13.21 |
|
|
|
100 |
% |
|
|
— |
|
|
|
1.52 |
|
|
|
(1.52 |
) |
|
|
(100 |
%) |
|
General & administrative |
|
$ |
1.34 |
|
|
|
1.23 |
|
|
$ |
0.11 |
|
|
|
9 |
% |
|
|
1.23 |
|
|
|
0.92 |
|
|
|
0.31 |
|
|
|
34 |
% |
|
(Gain) loss on sale of assets |
|
$ |
0.14 |
|
|
|
— |
|
|
$ |
0.14 |
|
|
NM |
|
|
|
— |
|
|
|
(1.42 |
) |
|
|
1.42 |
|
|
|
(100 |
%) |
|
NM – Not meaningful.
Depreciation, Depletion & Amortization (“DD&A”)
DD&A expense for 2014 was slightly higher than 2013. The increase in production volumes and DD&A rates associated with the continued development of the TMS was offset by lower DD&A rates in our Eagle Ford Shale Trend properties. TMS production increased to 18% of total production volumes in 2014 compared to 4% of total production volumes in 2013.
DD&A expense for 2013 decreased as compared to 2012 despite an increase in the DD&A rate between the periods. The decrease in DD&A expense resulted from lower 2013 production volumes. We calculated DD&A rates for the second half of 2013 using our mid-year reserve reports as of June 30, 2013. Our mid-year reserve report as of June 30, 2013 reflected additional proved reserves as a result of our activity in our Eagle Ford Shale Trend properties and drilling cost reductions, which partially offset the DD&A rate increase for the second half of 2013 and for 2013 overall.
Impairment
We recorded impairment expense of $331.9 million for the year ended December 31, 2014. The majority of the impairment expense, or $244.8 million, was recorded during the fourth quarter of 2014 and was related to our Eagle Ford Shale Trend properties.The impairment was driven by declining crude oil prices. In addition, we recorded $85.3 million of impairment expense during the third quarter of 2014 for properties that were sold in December 2014. We did not record impairment expense in 2013.
We recorded impairment expense of $47.8 million in the year ended December 31, 2012, $44.4 million of which related to our Angelina River trend field and was a result of declining natural gas prices. We calculated the fair value of our oil and natural gas properties based on a natural gas five year average futures strip price of $4.17 per Mcf.
General and Administrative Expense (“G&A”)
Although the rate per Mcfe increased, G&A expense decreased slightly in 2014 compared to 2013. Lower compensation expense and restructuring costs were partially offset by increased share based compensation. The higher rate per Mcfe reflects decreased natural gas production in 2014.
Share based compensation expense, which is a non-cash item, totaled $9.6 million, a $1.9 million increase over 2013 share based compensation expense. The increase in share based compensation reflects higher amortization expense associated with restricted stock awards to key employees.
G&A expense increased in 2013 compared to 2012. The increase reflects higher compensation expense, increased share based compensation and the restructuring cost of approximately $1.2 million associated with closing our Shreveport office. The consolidation of our administrative offices in Houston is expected to create operational efficiencies, but will not materially change our future G&A expenses.
36
Share based compensation expense, which is a non-cash item, amounted to $7.7 million in 2013 compared to $6.9 million in 2012. The increase in share based compensation reflects a restricted stock awarded to certain key employees in June 2012, which was amortized for the full year in 2013.
(Gain) loss on Sale of Assets
We recorded a $3.5 million loss on the sale of our interests in the Beckville, North Minden and West Brachfield fields located in Panola and Rusk Counties, Texas in 2014.
We recorded a gain of $44.6 million in the year ended December 31, 2012 representing the sale of our interest in three non-core properties, which included the sale of our South Henderson field in East Texas for a gain of $44.0 million.
Other Income (Expense)
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
|
|
(In thousands) |
|
|||||||||
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
(47,829 |
) |
|
$ |
(51,187 |
) |
|
$ |
(52,403 |
) |
|
Interest income and other |
|
|
90 |
|
|
|
101 |
|
|
|
4 |
|
|
Gain (loss) on derivatives not designated as hedges |
|
|
49,423 |
|
|
|
(702 |
) |
|
|
31,882 |
|
|
Loss on extinguishment of debt |
|
|
— |
|
|
|
(7,088 |
) |
|
|
— |
|
|
Income tax benefit (expense) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Average funded borrowings adjusted for debt discount |
|
|
554,095 |
|
|
|
552,935 |
|
|
|
606,801 |
|
|
Average funded borrowings |
|
|
559,616 |
|
|
|
567,494 |
|
|
|
631,129 |
|
Interest Expense
Our interest expense decreased in 2014 compared to 2013 as a result the reduction in our effective interest rate due to the exchange of our 5.0% Convertible Senior Notes due 2029 (the “2029 Notes) for our 5.0% Convertible Senior Notes due 2032 (the “2032 Notes”) that occurred in the second half of 2013. Also impacting the decline of interest expense was the Company repurchasing $45.1 million of the 2029 Notes on October 1, 2014. Non-cash interest of $10 million is included in the interest expense reported for the year 2014.
Our interest expense decreased in 2013 compared to 2012 as a result of the lower average level of outstanding debt in 2013. The lower average level of debt resulted from the repayment of the amounts due under our Senior Credit Facility with proceeds from our equity offerings. Non-cash interest of $12.7 million is included in the interest expense reported for the year 2013.
Gain (loss) on Derivatives Not Designated as Hedges
We produce and sell oil and natural gas into a market where prices are historically volatile. We enter into swap contracts, swaptions or other derivative agreements from time to time to manage our exposure to commodity price risk for a portion of our production.
Gain on derivatives not designated as hedges was $49.4 million for 2014. The gain includes $46.0 million representing the change in the fair value of our oil and natural gas derivative contracts and net cash receipts of $3.4 million on the settlement of our oil and natural gas derivatives. The change in fair value of our derivative contracts consisted of a $50.4 million gain on our oil derivatives and a $4.4 million loss on our natural gas derivatives. The increase in fair value of our oil derivatives reflects the decrease in futures prices for the period.
Loss on derivatives not designated as hedges was $0.7 million for 2013. The loss includes net cash settlement payments of $3.8 million and an increase in the fair value of our oil and natural gas derivative contracts of $3.1 million. The increase in fair value of our derivative contracts reflects the lower average futures strip prices at December 31, 2012 as compared to December 31, 2013 in addition to the expiration of the oil swaption contract.
37
Gain on derivatives not designated as hedges was $31.9 million for 2012. The gain includes net cash receipts of $73.2 million on our natural gas derivatives and a loss of $41.3 million representing the change in fair value of our oil and natural gas commodity contracts. The decrease in fair value reflects the higher average futures strip prices at December 31, 2011 as compared to December 31, 2012.
We will continue to be exposed to volatility in earnings resulting from changes in the fair value of our commodity contracts when we do not designate these contracts as hedges.
Loss on Extinguishment of Debt
On August 26, 2013 we exchanged half of our outstanding 2029 Notes for new 2032 Notes. We retired $109.25 million of outstanding 2029 Notes with a carrying value of $102.6 million and expensed unamortized debt issuance cost of $0.5 million, offset by $10.1 million attributable to the fair value of the equity portion of the 2029 Notes. The 2032 Notes had a fair value of $117.0 million, which resulted in a loss on extinguishment of debt of $4.8 million.
On October 1, 2013, we exchanged $57.4 million of our 2029 Notes for $57.0 million of new 2032 Notes. We retired the 2029 Notes with a carrying of $54.3 million and expensed unamortized debt issuance cost of $0.3 million, offset by $9.9 million attributable to the fair value of the equity portion of the 2029 Notes. The 2032 Notes had a fair value of $66.2 million, which resulted in a loss of on extinguishment of debt of $2.3 million.
Income Tax Benefit
We recorded no income tax benefit for the years 2014, 2013 and 2012. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred asset as of December 31, 2014.
Adjusted EBITDAX
Adjusted EBITDAX is a supplemental non-US GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as earnings before interest expense, income tax, DD&A, exploration expense, stock compensation expense and impairment of oil and gas properties. In calculating Adjusted EBITDAX, gains/losses on derivatives, less net cash received or paid in settlement of commodity derivatives are excluded from Adjusted EBITDAX. Other excluded items include Interest income and other, Gain/loss on sale of assets, Gain/loss on early extinguishment of debt and other expense. Adjusted EBITDAX is not a measure of net income (loss) as determined by US GAAP. Adjusted EBITDAX should not be considered an alternative to net income, as defined by US GAAP. The following table presents a reconciliation of the non-US GAAP measure of Adjusted EBITDAX to the US GAAP measure of net income (loss), its most directly comparable measure presented in accordance with US GAAP.
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
|
|
(In thousands) |
|
|||||||||
|
Net loss (US GAAP) |
|
$ |
(353,136 |
) |
|
$ |
(95,186 |
) |
|
$ |
(84,202 |
) |
|
Depreciation, depletion and amortization |
|
|
135,716 |
|
|
|
135,357 |
|
|
|
141,222 |
|
|
Exploration Expense |
|
|
6,206 |
|
|
|
22,774 |
|
|
|
23,122 |
|
|
Impairment |
|
|
331,931 |
|
|
|
— |
|
|
|
47,818 |
|
|
Loss on extinguishment of debt |
|
|
— |
|
|
|
7,088 |
|
|
|
— |
|
|
Stock based compensation |
|
|
9,555 |
|
|
|
7,680 |
|
|
|
6,903 |
|
|
Interest expense |
|
|
47,829 |
|
|
|
51,187 |
|
|
|
52,403 |
|
|
(Gain) loss on derivatives not designated as hedges |
|
|
(49,423 |
) |
|
|
702 |
|
|
|
(31,882 |
) |
|
Net cash received (paid) in settlement of derivative instruments |
|
|
3,417 |
|
|
|
(3,786 |
) |
|
|
73,160 |
|
|
Other items (1) |
|
|
7,202 |
|
|
|
(299 |
) |
|
|
(44,519 |
) |
|
Adjusted EBITDAX |
|
$ |
139,297 |
|
|
$ |
125,517 |
|
|
$ |
184,025 |
|
|
(1) |
Other items include interest income and other, gain/loss on sale of assets, income taxes and other expense. |
Management believes Adjusted EBITDAX is a good financial indicator of our ability to internally generate operating funds.
38
Management believes that this non-US GAAP financial measure provides useful information to investors because it is monitored and used by our management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and gas exploration and production industry. Our computations of Adjusted EBITDAX may not be comparable to other similarly totaled measures of other companies.
LIQUIDITY AND CAPITAL RESOURCES
Overview Our primary sources of cash during 2014 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from the sale of our non-core assets. We used cash in 2014 to fund our capital spending program, pay down debt, pay interest on outstanding debt, and pay preferred stock dividends. Our primary sources of cash during 2013 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility, proceeds from our Series C and D Preferred Stock and our common stock offerings. We used cash in 2013 to fund our capital spending program and the TMS acreage acquisition, pay down debt, pay interest on outstanding debt, and pay preferred stock dividends. Our primary sources of cash during 2012 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from sale of assets. We primarily used cash in 2012 to fund our capital spending program, pay interest on outstanding debt and pay preferred stock dividends.
We have in place a $600 million Senior Credit Facility, entered into with a syndicate of U.S. and international lenders. As of December 31, 2014, we had a $230.0 million borrowing base with $121.0 million in outstanding borrowings. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. We were in compliance with existing covenants under the Senior Credit Facility at December 31, 2014.
The Thirteenth Amendment to our Senior Credit Facility, which became effective on February 26, 2015, includes the following key elements:
|
· |
reduces our borrowing base to $200 million on February 26, 2015; |
|
· |
on the earlier of April 1, 2015 or the funding of the $100 million second lien senior secured notes, our borrowing base will be reduced to $150 million; |
|
· |
the next redetermination of our borrowing base will occur on October 1, 2015; |
|
· |
extends the maturity date of the Senior Credit Facility to February 24, 2017; |
|
· |
eliminates our current Total Debt to EBITDAX covenant and replaces it with a Maximum Secured Debt to EBITDAX covenant of 2.50x. Maximum Secured Debt is defined as first and second lien debt only; and |
|
· |
revises our Minimum Interest Coverage Ratio to 2.00x. |
On February 26, 2015 we entered into a definitive agreement to issue an aggregate principal amount of $100 million of second lien senior secured notes that will mature in 2018. The proceeds of the note issuance will be used to pay down the amount drawn on our Senior Credit Facility.
Outlook
Our total capital expenditures for 2015 are expected to be approximately $90 to $110 million, with flexibility to increase or decrease based on the movement of commodity prices. We plan to spend approximately $80 to $100 million on drilling and completion cost and $10 million on leasehold and infrastructure costs. We plan to focus our 2015 drilling efforts in the TMS by allocating approximately 90% of our total capital budget, to the play. We believe that our expected level of operating cash flows and our borrowing capacity will be sufficient to fund our projected operational and capital programs for 2015.
In addition, to support 2015 cash flows, we entered into strategic derivative positions as of December 31, 2014, covering approximately 70% of our anticipated oil and condensate sales volumes for 2015. See Note 8—“Derivative Activities” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
We continuously monitor our balance sheet and coordinate our capital program with our expected cash flows and scheduled debt repayments. We will continue to evaluate funding alternatives as needed.
39
Alternatives available to us may include:
|
· |
issuance of debt or equity securities; |
|
· |
joint venture partnerships in our TMS, Eagle Ford Shale Trend, and/or core Haynesville Shale acreage; |
|
· |
availability under our Senior Credit Facility; and |
|
· |
sale of non-core assets. |
The following section discusses significant sources and uses of cash for the three-year period ending December 31, 2014. Forward-looking information related to our liquidity and capital resources are discussed above in Outlook.
Capital Resources
We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts and future acquisitions with cash flows from our operations and borrowings under our Senior Credit Facility. In the future, as we have done on several occasions over the last few years, we may also access public markets to issue additional debt and/or equity securities enter into joint ventures or sell non-core assets.
Our primary sources of cash during 2014 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from the sale of non-core assets.
Our primary sources of cash during 2013 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and the proceeds from our underwritten public offerings of $110 million of our 10% Series C Preferred Stock (the “Series C Preferred Stock”), $130 million of our 9.75% Series D Preferred Stock (the “Series D Preferred Stock”) and 6,900,000 shares of our common stock.
Our primary sources of cash during 2012 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from the sale of assets.
The table below summarizes the sources of cash during 2014, 2013 and 2012:
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
||||||||||||||||||
|
Cash flow statement information: |
|
2014 |
|
|
2013 |
|
|
Variance |
|
|
2013 |
|
|
2012 |
|
|
Variance |
|
||||||
|
|
|
(In thousands) |
|
|||||||||||||||||||||
|
Net Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provided by operating activities |
|
$ |
121,733 |
|
|
$ |
71,405 |
|
|
$ |
50,328 |
|
|
$ |
71,405 |
|
|
$ |
173,789 |
|
|
$ |
(102,384 |
) |
|
Used in investing activities |
|
|
(268,422 |
) |
|
|
(250,654 |
) |
|
|
(17,768 |
) |
|
|
(250,654 |
) |
|
|
(161,494 |
) |
|
|
(89,160 |
) |
|
Provided by (used) financing activities |
|
|
97,477 |
|
|
|
227,281 |
|
|
|
(129,804 |
) |
|
|
227,281 |
|
|
|
(14,454 |
) |
|
|
241,735 |
|
|
Increase (decrease) in cash and cash equivalents |
|
$ |
(49,212 |
) |
|
$ |
48,032 |
|
|
$ |
(97,244 |
) |
|
$ |
48,032 |
|
|
$ |
(2,159 |
) |
|
$ |
50,191 |
|
At December 31, 2014, we had a working capital deficit of $79.4 million and long-term debt, net of debt discount, of $568.6 million.
Cash Flows
Year ended December 31, 2014 Compared to Year ended December 31, 2013
Operating activities: Production from our wells, the price of oil and natural gas and operating costs represent the main drivers of our cash flow from operations. Changes in working capital also impact cash flows. Net cash provided by operating activities for 2014 totaled $121.7 million, up $50.3 million from 2013. The two main drivers for the increase include operating revenues and changes in working capital. Operating revenues increased $6.0 million in 2014 compared to 2013 reflecting the increase in oil production volumes and higher average realized natural gas sales prices. The $38.2 million change in working capital, from $12.7 million negative working capital in 2013 to $25.5 million positive working capital in 2014, results from timing of drilling and completion activity for each respective year-end.
Investing activities: Net cash used in investing activities was $268.4 million for the year ended December 31, 2014, compared to $250.7 million for the year ended December 31, 2013. While we booked capital expenditures of approximately $332.9 million in
40
2014, we paid out cash amounts totaling $322.3 million in 2014. The difference is attributed to $22.5 million accrued at December 31, 2013 and paid in 2014 and a $0.7 million non-cash reclass to exploration expense offset by $33.8 million in drilling and completion costs accrued at December 31, 2014. Capital expenditures in 2014 were offset by the receipt of $53.9 million in net proceeds, primarily from the sale of non-core assets located in east Texas.
We conducted drilling and completion operations on 30 gross wells in 2014 compared to 25 gross wells in 2013. Of the $322.3 million cash spent in 2014, $289.4 million was for drilling and completion activities (of which $21.5 million related to 2013 wells); $23.2 million was for leasehold acquisition, $3.3 million for facilities and infrastructure, $5.7 million for capital workovers and $0.7 million for furniture, fixtures and equipment. Of the $251.1 million cash spent in 2013, $209.0 million was for drilling and completion activities (of which $18.6 million related to 2012 wells); $23.5 million was for property acquisition, $14.9 million was for leasehold acquisition, $1.1 million for facilities and infrastructure, $1.9 million for capital workovers and $0.7 million for furniture, fixtures and equipment.
Financing activities: Net cash provided in financing activities for 2014 consisted of net proceeds from borrowings under our Senior Credit Facility of $121.0 million and $51.8 million from the release of escrowed funds for redemption of the 2029 notes, partially offset by $45.1 million repurchase of the 2029 Notes and preferred stock dividends of $29.7 million. We had $121 million in borrowings outstanding under our Senior Credit Facility as of December 31, 2014.
Year ended December 31, 2013 Compared to Year Ended December 31, 2012
Operating activities: Production from our wells, the price of oil and natural gas and operating costs represent the main drivers behind our cash flow from operations. Changes in working capital also impact cash flows. Net cash provided by operating activities decreased $102.4 million in 2013. The three main drivers for the variance between 2013 and 2012 include the net cash received to settle derivatives not designated as hedges, operating revenues and changes in working capital. The net cash received to settle derivatives not designated as hedges of $73.2 million for 2012 compared to net cash paid to settle on derivatives not designated as hedges of $3.8 million in 2013 led to a variance of $77.0 million. Partially offsetting this variance was an increase in operating revenues of $22.5 million from 2012 of $180.5 million to $202.6 million for 2013. The combination of increases in oil sales volumes and realized sales prices drove the increase in operating revenues. Oil volumes as a percentage of total volumes grew to 29% in 2013 from 21% in 2012. Average realized sales prices increased to $7.29 per Mcfe in 2013 from $5.75 per Mcfe in 2012. The difference in changes in working capital of $45 million from 2012 of $32.3 million in positive working capital changes to $12.7 million in negative working capital changes for 2013 results from timing of payments related to drilling and completion activity for each respective year-end.
Investing activities: Net cash used in investing activities was $250.7 million for the year ended December 31, 2013, compared to $161.5 million for 2012. While we booked capital expenditures of approximately $256.8 million in 2013, we paid out cash amounts totaling $251.1 million in 2013, with differences being attributed to approximately $22.5 million in drilling and completion costs, which were accrued at December 31, 2013 and non-cash asset retirement obligation additions of $1.8 million offset by $19.2 million in drilling and completion cost accrued at December 31, 2012 of which $18.6 million was paid in 2013. Net cash used in investing activities was offset by the receipt of $0.4 million of cash proceeds from the sale of fixed assets in 2013.
We drilled 25 gross wells in 2013 compared to 46 gross wells in 2012. Of the $251.1 million cash spent in 2013, $209.0 million was for drilling and completion activities (of which $18.6 million related to 2012 wells); $23.5 million was for property acquisition, $14.9 million was for leasehold acquisition, $1.1 million for facilities and infrastructure, $1.9 million for capital workovers and $0.7 million for furniture, fixtures and equipment. Of the $252.4 million cash spent in 2012, $220.8 million was for drilling and completion activities (of which $20.8 million related to 2011 wells); $22.3 million was for leasehold acquisition, $5.2 million for facilities and infrastructure, $3.5 million for capital workovers and $0.6 million for furniture, fixtures and equipment.
Financing activities: The cash provided by financing activities for 2013 consisted primarily of $230.6 million in net proceeds from our offerings of Series C Preferred Stock and Series D Preferred Stock and net proceeds of $166.1 million from our offering of common stock. The cash used in financing activities consisted primarily of the net $95 million repayment of the amount outstanding under our Senior Credit Facility, establishment of escrow of $51.8 million for the repayment of our 2029 Notes, payment of preferred stock dividends of $18.6 million and $4.8 million in debt and equity issuance costs.
41
Debt consisted of the following balances as of the dates indicated (in thousands):
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
||||||||||||||||||
|
|
|
Principal |
|
|
Carrying Amount |
|
|
Fair Value (1) |
|
|
Principal |
|
|
Carrying Amount |
|
|
Fair Value (1) |
|
||||||
|
Senior Credit Facility |
|
$ |
121,000 |
|
|
$ |
121,000 |
|
|
$ |
121,000 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
3.25% Convertible Senior Notes due 2026 |
|
|
429 |
|
|
|
429 |
|
|
|
353 |
|
|
|
429 |
|
|
|
429 |
|
|
|
429 |
|
|
5.0% Convertible Senior Notes due 2029 (2) |
|
|
6,692 |
|
|
|
6,692 |
|
|
|
3,480 |
|
|
|
51,816 |
|
|
|
49,663 |
|
|
|
51,686 |
|
|
5.0% Convertible Senior Notes due 2032 (3) |
|
|
170,770 |
|
|
|
165,504 |
|
|
|
87,093 |
|
|
|
167,405 |
|
|
|
160,437 |
|
|
|
171,863 |
|
|
8.875% Senior Notes due 2019 |
|
|
275,000 |
|
|
|
275,000 |
|
|
|
136,125 |
|
|
|
275,000 |
|
|
|
275,000 |
|
|
|
288,063 |
|
|
Total debt |
|
$ |
573,891 |
|
|
$ |
568,625 |
|
|
$ |
348,051 |
|
|
$ |
494,650 |
|
|
$ |
485,529 |
|
|
$ |
512,041 |
|
|
(1) |
The carrying amount for the Senior Credit Facility represents fair value as the variable interest rates are reflective of current market conditions. The fair value of the notes was obtained by direct market quotes within Level 1 of the fair value hierarchy as defined in part II Item 8 of this Annual Report on Form 10-K. |
|
(2) |
The debt discount is amortized using the effective interest rate method based upon an original five year term through October 1, 2014. The debt discount was zero and $2.1 million as of December 31, 2014 and December 31, 2013, respectively. |
|
(3) |
The debt discount is amortized using the effective interest rate method based upon a four year term through October 1, 2017, the first repurchase date applicable to the 2032 Notes. The debt discount was $5.3 million and $7.0 million as of December 31, 2014 and December 31, 2013, respectively. |
The following table summarizes the total interest expense (contractual interest expense, amortization of debt discount and financing costs) and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates) for the years ended:
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
|
December 31, 2012 |
|
|||||||||||||||
|
|
|
Interest Expense |
|
|
Effective Interest Rate |
|
|
Interest Expense |
|
|
Effective Interest Rate |
|
|
Interest Expense |
|
|
Effective Interest Rate |
|
||||||
|
Senior Credit Facility |
|
$ |
3,943 |
|
|
|
5.2 |
% |
|
$ |
3,936 |
|
|
|
5.3 |
% |
|
$ |
5,114 |
|
|
|
3.7 |
% |
|
3.25% Convertible Senior Notes due 2026 |
|
|
14 |
|
|
|
3.3 |
% |
|
|
14 |
|
|
|
3.3 |
% |
|
|
14 |
|
|
|
3.3 |
% |
|
5.0% Convertible Senior Notes due 2029 |
|
|
4,363 |
|
|
|
11.0 |
% |
|
|
17,400 |
|
|
|
11.4 |
% |
|
|
21,968 |
|
|
|
11.4 |
% |
|
5.0% Convertible Senior Notes due 2032 |
|
|
14,201 |
|
|
|
8.7 |
% |
|
|
4,529 |
|
|
|
8.8 |
% |
|
|
— |
|
|
|
— |
|
|
8.875% Senior Notes due 2019 |
|
|
25,308 |
|
|
|
9.2 |
% |
|
|
25,308 |
|
|
|
9.2 |
% |
|
|
25,308 |
|
|
|
9.2 |
% |
Senior Credit Facility
Total lender commitments under the Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”) are $600 million subject to borrowing base limitation, which as of December 31, 2014 was $230 million. Pursuant to the terms of the Senior Credit Facility borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. As of December 31, 2014, we had $121.0 million outstanding under the Senior Credit Facility. In February 2015, we entered into the Thirteenth Amendment with an effective date of February 26, 2015. On the effective date, the Thirteenth Amendment reduced our borrowing base to $200 million and extended the maturity of the Senior Credit Facility to February 24, 2017. On February 26, 2015 we entered into a definitive agreement to issue $100 million of second lien senior secured notes, which will be used to pay down the amount drawn on our Senior Credit Facility. Our borrowing base will be further reduced to $150 million on the earlier of April 1, 2015 or the funding of the $100 million second lien senior secured notes. The next borrowing base redetermination will occur on October 1, 2015. Interest on revolving borrowings under the Senior Credit Facility, as amended, accrues at a rate calculated, at our option, at the bank base rate plus 1.25% to 2.25% or LIBOR plus 2.25% to 3.25%, depending on borrowing base utilization. Substantially all our assets are pledged as collateral to secure the Senior Credit Facility.
The terms of the Senior Credit Facility as amended by the Thirteenth Amendment, require us to maintain certain covenants. Capitalized terms used here, but not defined, have the meanings assigned to them in the Senior Credit Facility. The primary financial covenants include:
|
· |
Current Ratio of 1.0/1.0; |
|
· |
Interest Coverage Ratio of EBITDAX of not less than 2.0/1.0 for the trailing four quarters EBITDAX. The interest for such period to apply solely to the cash portion of interest expense; and |
|
· |
Maximum Secured Debt no greater than 2.5 times EBITDAX for the trailing four quarters. |
42
As used in connection with the Senior Credit Facility, Current Ratio is consolidated current assets (including current availability under the Senior Credit Facility, but excluding non-cash assets related to our derivatives) to consolidated current liabilities (excluding non-cash liabilities related to our derivatives, accrued capital expenditures and current maturities under the Senior Credit Facility).
As used in connection with the Senior Credit Facility, EBITDAX is earnings before interest expense, income tax, depreciation, depletion and amortization, exploration expense, stock based compensation and impairment of oil and natural gas properties. In calculating EBITDAX for this purpose, gains/losses on derivatives not designated as hedges, less net cash received (paid) in settlement of commodity derivatives are excluded from Adjusted EBITDAX.
We were in compliance with all the financial covenants of the Senior Credit Facility as of December 31, 2014 which on that date were:
|
· |
Current Ratio of 1.0/1.0; |
|
· |
Interest Coverage Ratio of EBITDAX of not less than 2.5/1.0 on an annualized basis when measured for the second, third and fourth quarters of 2014, which was based on annualized interim EBITDAX amounts rather than trailing four quarters. The interest for such period applied solely to the cash portion of interest expense; and |
|
· |
Total Debt no greater than 4.0 times EBITDAX for the trailing four quarters. Provided that such ratio, when measured for the third and fourth quarters of 2014 was based on annualized interim EBITDAX amounts rather than trailing four quarters. |
8.875% Senior Notes due 2019
On March 2, 2011, we sold $275 million of our 8.875% Senior Notes due 2019 (the “ 2019 Notes”). The 2019 Notes mature on March 15, 2019, unless earlier redeemed or repurchased. The 2019 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2019 Notes accrue interest at a rate of 8.875% annually, and interest is paid semi-annually in arrears on March 15 and September 15. The 2019 Notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility.
After March 15, 2015, we may redeem all or a portion of the 2019 Notes at redemption prices (expressed as percentages of principal amount) equal to (i) 104.438% for the twelve-month period beginning on March 15, 2015; (ii) 102.219% for the twelve-month period beginning on March 15, 2016 and (iii) 100.000% on or after March 15, 2017, in each case plus accrued and unpaid interest to the redemption date. In addition, prior to March 15, 2015, we may redeem all or a part of the 2019 Notes at a redemption price equal to 100% of the principal amount of the 2019 Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest to the redemption date.
The indenture governing the 2019 Notes restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem or retire such capital stock; (iii) sell assets, including the capital stock of our restricted subsidiaries; (iv) pay dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. These covenants are subject to a number of important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indenture governing the 2019 Notes) has occurred and is continuing, many of these covenants will terminate.
5% Convertible Senior Notes due 2029
In September 2009, we sold $218.5 million of our 2029 Notes. The 2029 Notes mature on October 1, 2029, unless earlier converted, redeemed or repurchased. As of December 31, 2014, $6.7 million in aggregate principal amount of the 2029 Notes remain outstanding.
The 2029 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2029 Notes accrue interest at a rate of 5% annually, and interest is paid semi-annually in arrears on April 1 and October 1 of each year.
We exchanged $166.7 million of 2029 Notes for 2032 Notes in 2013. On October 1, 2014, we repurchased $45.1 million of the 2029 Notes using the restricted cash held in escrow for that purpose.
The 2029 Notes are convertible into shares of our common stock at a rate equal to 28.8534 shares per $1,000 principal amount of 2029 Notes (equal to an initial conversion price of approximately $34.66 per share of common stock per share).
43
Investors may convert their 2029 Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances: (1) during any fiscal quarter (and only during such fiscal quarter), if the last reported sale price of our common stock is greater than or equal to 135% of the conversion price of the 2029 Notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter; (2) if the 2029 Notes have been called for redemption or (3) upon the occurrence of one of specified corporate transactions. Investors may also convert their 2029 Notes at their option at any time beginning on September 1, 2029, and ending at the close of business on the second business day immediately preceding the maturity date.
We separately accounted for the liability and equity components of our 2029 Notes in a manner that reflected our nonconvertible debt borrowing rate when interest was recognized through September 30, 2014. The debt discount was amortized using the effective interest rate method based upon an original five year term through October 1, 2014. The debt discount on the 2029 Notes was fully amortized as of December 31, 2014.
5% Convertible Senior Notes due 2032
We entered into separate, privately negotiated exchange agreements in 2013 under which we retired $166.7 million in aggregate principal amount of our outstanding 2029 Notes in exchange for the issuance of the 2032 Notes in an aggregate principal amount of $166.3 million. The 2032 Notes will mature on October 1, 2032.
Many terms of the 2032 Notes remain the same as the 2029 Notes they replaced, including the 5.0% annual cash interest rate and the conversion rate of 28.8534 shares of our common stock per $1,000 principal amount of 2032 Notes (equivalent to an initial conversion price of approximately $34.6580 per share of common stock), subject to adjustment in certain circumstances.
Unlike the 2029 Notes, the principal amount of the 2032 Notes accretes at a rate of 2% per year commencing August 26, 2013, compounding on a semi-annual basis, until October 1, 2017. The accreted portion of the principal is payable in cash upon maturity but does not bear cash interest and is not convertible into our common stock. Holders have the option to require us to purchase any outstanding 2032 Notes on each of October 1, 2017, 2022 and 2027, at a price equal to 100% of the principal amount plus the accretion thereon. Accretion of principal is and will be reflected as a non-cash component of interest expense on our statement of operations during the term of the 2032 Notes. We recorded $3.4 million of accretion during 2014.
We have the right to redeem the 2032 Notes on or after October 1, 2016 at a price equal to 100% of the principal amount, plus accrued but unpaid interest and accretion thereon. The 2032 Notes also provide us with the option, at our election, to convert the new notes in whole or in part, prior to maturity, into the underlying common stock, provided the trading price of our common stock exceeds $45.06 (or 130% of the then applicable conversion price) for the required measurement period. If we elect to convert the 2032 Notes on or before October 1, 2016, holders will receive a make-whole premium.
We separately account for the liability and equity components of our 2032 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. We measured the debt component of the 2032 Notes using an effective interest rate of 8%. We attributed $158.8 million of the fair value to the 2032 Note to debt component which compared to the face results in a debt discount of $7.5 million which will be amortized through the first put date of October 1, 2017. Additionally, we recorded $24.4 million within additional paid-in capital representing the equity component of the 2032 Notes. A debt discount of $5.3 million remains to be amortized on the 2032 Notes as of December 31, 2014.
3.25% Convertible Senior Notes Due 2026
At December 31, 2014, $0.4 million of our 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”) remained outstanding. Holders may present to us for redemption the remaining outstanding 2026 Notes on December 1, 2016 and December 1, 2021.
Upon conversion, we have the option to deliver shares at the applicable conversion rate, redeem in cash or in certain circumstances redeem in a combination of cash and shares.
44
The 2026 Notes are convertible into shares of our common stock at a rate equal to the sum of:
|
a) |
15.1653 shares per $1,000 principal amount of 2026 Notes (equal to a “base conversion price” of approximately $65.94 per share) plus |
|
b) |
an additional amount of shares per $1,000 of principal amount of 2026 Notes equal to the incremental share factor 2.6762), multiplied by a fraction, the numerator of which is the applicable stock price less the “base conversion price” and the denominator of which is the applicable stock price. |
5.375% Series B Convertible Preferred Stock
During 2005 and 2006 we issued a total of 2,250,000 shares of our 5.375% Series B Convertible Preferred Stock (the “Series B Preferred Stock”) for net aggregate proceeds of $108.8 million (after offering costs of $2.7 million). Each share of the Series B Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears.
10% Series C Cumulative Preferred Stock
In April 2013, we issued $110 million of Series C Preferred Stock and received $105.4 million in net proceeds from the sale. The sale consisted of 4,400,000 depositary shares each representing a 1/1000th ownership interest in a share of Series C Preferred Stock, par value $1.00 per preferred share with a liquidation preference of $25,000 per preferred share ($25.00 per depositary share) in an underwritten public offering.
The Series C Preferred Stock ranks senior to our common stock and on parity with our Series B Preferred Stock and our Series D Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series C Preferred Stock has no stated maturity and is not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common stock in connection with certain changes of control.
At any time on or after April 10, 2018, we may, at our option, redeem the Series C Preferred Stock, in whole at any time or in part from time to time, for cash at a redemption price of $25,000 per preferred share, plus all accumulated and unpaid dividends to, but not including, the date of redemption. We may redeem the Series C Preferred Stock following certain changes of control, if we do not exercise this option, then the holders of the Series C Preferred Stock have the option to convert the shares of preferred stock into up to 3,371.54 shares of our common stock per share of Series C Preferred Stock, subject to certain adjustments. If we exercise any of our redemption rights relating to shares of Series C Preferred Stock, the holders of Series C Preferred Stock will not have the conversion right described above with respect to the shares of Series C Preferred Stock called for redemption.
Holders of the Series C Preferred Stock have no voting rights except for limited voting rights if we fail to pay dividends for six or more quarterly periods (whether or not consecutive) and in certain other limited circumstances or as required by law.
We used the net proceeds from the offering of our Series C Preferred Stock to enhance liquidity and financial flexibility through the repayment of borrowings outstanding under our Senior Credit Facility and used the remainder for general corporate purposes.
9.75% Series D Cumulative Preferred Stock
In August 2013, we issued $130 million of Series D Preferred Stock and received $124.9 million net proceeds from the sale. The sale consisted of 5,200,000 depositary shares each representing a 1/1000th ownership interest in a share of Series D Preferred Stock, par value $1.00 per preferred share with a liquidation preference of $25,000 per preferred share ($25.00 per depositary share) in an underwritten public offering.
The Series D Preferred Stock ranks senior to our common stock and on parity with our Series B Preferred Stock and our Series C Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series D Preferred Stock has no stated maturity and is not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common stock in connection with certain changes of control.
At any time on or after August 19, 2018, we may, at our option, redeem the Series D Preferred Stock, in whole at any time or in part from time to time, for cash at a redemption price of $25,000 per preferred share, plus all accumulated and unpaid dividends to, but
45
not including, the date of redemption. We may redeem the Series D Preferred Stock following certain changes of control, if we do not exercise this option, then the holders of the Series D Preferred Stock have the option to convert the shares of preferred stock into up to 2,297.79 shares of our common stock per share of Series D Preferred Stock, subject to certain adjustments. If we exercise any of our redemption rights relating to shares of Series D Preferred Stock, the holders of Series D Preferred Stock will not have the conversion right described above with respect to the shares of Series D Preferred Stock called for redemption.
Holders of the Series D Preferred Stock have no voting rights except for limited voting rights if we fail to pay dividends for six or more quarterly periods (whether or not consecutive) and in certain other limited circumstances or as required by law.
We used the net proceeds from the offering of our Series D Preferred Stock to enhance liquidity and financial flexibility through the repayment of borrowings outstanding under our Senior Credit Facility, fund our acquisition of additional TMS acreage and used the remainder for general corporate purposes.
For additional information on our debt and equity instruments, see Note 4—“Debt” and 7—“Stockholders’ Equity” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
Future Commitments
The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2014. In addition to the contractual obligations presented in the table below, our Consolidated Balance Sheet at December 31, 2014 reflects accrued interest on our bank debt of $9.3 million payable in the first half of 2015. For additional information see Note 4-“Long-Term Debt” and Note 9-“Commitments and Contingencies” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
|
|
|
Payment due by Period |
|
|||||||||||||||||||||||||
|
|
|
Note |
|
|
Total |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 and After |
|
|||||||
|
Debt (1) |
|
|
4 |
|
|
$ |
462,496 |
|
|
$ |
— |
|
|
$ |
429 |
|
|
$ |
180,375 |
|
|
$ |
— |
|
|
$ |
281,692 |
|
|
Interest on notes |
|
|
4 |
|
|
|
127,185 |
|
|
|
33,067 |
|
|
|
33,066 |
|
|
|
30,975 |
|
|
|
24,741 |
|
|
|
5,336 |
|
|
Office space leases |
|
|
|
|
|
|
4,914 |
|
|
|
983 |
|
|
|
1,020 |
|
|
|
1,057 |
|
|
|
1,093 |
|
|
|
761 |
|
|
Office equipment leases |
|
|
|
|
|
|
311 |
|
|
|
231 |
|
|
|
62 |
|
|
|
18 |
|
|
|
— |
|
|
|
— |
|
|
Drilling rigs & operations contracts |
|
|
|
|
|
|
7,065 |
|
|
|
6,946 |
|
|
|
97 |
|
|
|
22 |
|
|
|
— |
|
|
|
— |
|
|
Transportation contracts |
|
|
|
|
|
|
5,391 |
|
|
|
1,264 |
|
|
|
1,032 |
|
|
|
1,032 |
|
|
|
1,032 |
|
|
|
1,031 |
|
|
Total contractual obligations (2) |
|
|
|
|
|
$ |
607,362 |
|
|
$ |
42,491 |
|
|
$ |
35,706 |
|
|
$ |
213,479 |
|
|
$ |
26,866 |
|
|
$ |
288,820 |
|
|
|
|
(1) |
The 2026 Notes have a provision at the end of years five, ten and 15, for the investors to demand payment on these dates; the first such date was December 1, 2011; all but the remaining $0.4 million were redeemed. The next ‘put’ date for the remaining 2026 Notes is December 1, 2016. The 2029 Notes have a provision by which on or after October 1, 2014, we may redeem all or a portion of the 2029 Notes for cash and the investors may require us to repurchase the 2029 Notes on each of October 1, 2014, 2019 and 2024; all but the remaining $6.7 million were redeemed. The 2032 Notes have a provision by which on or after October 1, 2017, we may redeem all or a portion of the 2032 Notes for cash and the investors may require us to repurchase the 2032 Notes on each of October 1, 2017, 2022 and 2027. |
|
(2) |
This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $6.5 million as of December 31, 2014. We record a separate liability for the fair value of this asset retirement obligation. See Note 3-“Asset Retirement Obligations” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K. |
Summary of Critical Accounting Policies
The following summarizes several of our critical accounting policies. See a complete list in Note 1–“Description of Business and Accounting Policies” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
Proved Oil and Natural Gas Reserves
Proved reserves are defined by the SEC as those quantities of oil and natural gas which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is
46
a deterministic estimate or probabilistic estimate. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well. Although our external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.
While the estimates of our proved reserves at December 31, 2014 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could differ materially from our actual results.
Successful Efforts Accounting
We use the successful efforts method to account for exploration and development expenditures and to calculate DD&A. Unsuccessful exploration wells, as well as other exploration expenditures such as seismic costs, are expensed and can have a significant effect on operating results. Successful exploration drilling costs, all development capital expenditures and asset retirement costs are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by engineers. Leasehold costs are charged to expense using the units of production method based on total proved oil and natural gas reserves.
Fair Value Measurement
Fair value is defined by Accounting Standards Codification (“ASC”) 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We carry our derivative instruments at fair value and measure their fair value by applying the income approach provided for ASC 820, using Level 2 inputs based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our credit worthiness or that of our counterparties. We carry our oil and natural gas properties held for use at historical cost. We use Level 3 inputs, which are unobservable data such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices to determine the fair value of our oil and natural gas properties in determining impairment. We carry cash and cash equivalents, account receivables and payables at carrying value which represent fair value because of the short-term nature of these instruments. For definitions for Level 1, Level 2 and Level 3 inputs see Note 1-“Description of Business and Accounting Policies” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
Impairment of Properties
We monitor our long-lived assets recorded in oil and natural gas properties in the Consolidated Balance Sheets to ensure that they are not carried in excess of fair value. We must evaluate our properties for potential impairment when certain indicators or circumstances indicate that the carrying value of an asset could exceed its fair value. Performing these evaluations requires a significant amount of judgment since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable proved and probable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserves or other changes to contracts, environmental regulations or tax laws. We cannot predict the amount of impairment charges that may be recorded in the future.
Asset Retirement Obligations
We make estimates of the future costs of the retirement obligations of our producing oil and natural gas properties in order to record the liability as required by the applicable accounting standard. This requirement necessitates us to make estimates of our property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.
47
Income Taxes
We are subject to income and other related taxes in areas in which we operate. When recording income tax expense, certain estimates are required by management due to timing and the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate our tax operating loss and other carry-forwards to determine whether a gross deferred tax asset, as well as a related valuation allowance, should be recognized in our financial statements.
Accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See Note 1-“Description of Business and Accounting Policies-Income Taxes” and Note 6-“Income Taxes” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
Share-Based Compensation Plans
For all new, modified and unvested share-based payment transactions with employees, we measure the fair value on the grant date and recognize it as compensation expense over the requisite period. The fair value of each option award is estimated using a Black-Scholes option valuation model that requires us to develop estimates for assumptions used in the model. The Black-Scholes valuation model uses the following assumptions: expected volatility, expected term of option, risk-free interest rate and dividend yield. Expected volatility estimates are developed by us based on historical volatility of our stock. We use historical data to estimate the expected term of the options. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield in effect at the grant date. Our common stock does not pay dividends therefore, the dividend yield is zero. The fair value of restricted stock is measured using the close of the day stock price on the day of the award.
New Accounting Pronouncements
See Note 1-“Description of Business and Accounting Policies”- “New Accounting Pronouncements” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
Off-Balance Sheet Arrangements
We do not currently have any off-balance sheet arrangements for any purpose.
48
Our primary market risks are attributable to fluctuations in commodity prices and interest rates. These fluctuations can affect revenues and cash flow from operating, investing and financing activities. Our risk-management policies provide for the use of derivative instruments to manage these risks. The types of derivative instruments utilized by us include futures, swaps, options and fixed-price physical-delivery contracts. The volume of commodity derivative instruments utilized by us may vary from year to year and is governed by risk-management policies with levels of authority delegated by the Board of Directors. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and we may be required from time to time to deposit cash or provide letters of credit with exchange brokers or its counterparties in order to satisfy these margin requirements.
For information regarding our accounting policies and additional information related to our derivative and financial instruments, see Note 1—“Summary of Significant Accounting Policies”, Note 8—“Derivative Instruments” and Note 4—“Debt” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.
Commodity Price Risk
Our most significant market risk relates to fluctuations in natural gas and crude oil prices. Management expects the prices of these commodities to remain volatile and unpredictable. As these prices decline or rise significantly, revenues and cash flow will also decline or rise significantly. In addition, additional non-cash write-down of our oil and natural gas properties may be required if future commodity prices experience a sustained and significant decline. Below is a sensitivity analysis of our commodity-price-related derivative instruments.
We had derivative instruments in place to reduce the price risk associated with production in 2015 of approximately 3,500 Bbls per day of crude oil as of December 31, 2014. At December 31, 2014, we had a net asset derivative position of $46.9 million related to these derivative instruments. We do not enter into derivatives instruments for trading purposes. Utilizing actual derivative contractual volumes, a hypothetical 10% increase in underlying commodity prices would have decreased the net derivative asset position to $39.4 million, while a hypothetical 10% decrease in underlying commodity prices would have increased the net derivative asset to $54.4 million. However, a gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instruments.
Interest Rate Risk
As of December 31, 2014, we had $121.0 million outstanding variable-rate debt and $452.8 million of principal fixed-rate debt. To the extent we incur borrowings under our Senior Credit Facility our exposure to variable interest rates will increase. In the past, we have entered into interest rate swaps to help reduce our exposure to interest rate risk, and we may seek to do so in the future if we deem appropriate. As of December 31, 2014, we had no interest rate swaps.
Credit Risks
Our exposure to non-payment or non-performance by our customers and counterparties presents a credit risk. Generally, non-payment or non-performance results from a customer’s or counterparty’s inability to satisfy obligations. We monitor the creditworthiness of our customers and counterparties and established credit limits according to our credit policies and guidelines. We have the ability to require cash collateral as well as letters of credit from our financial counterparties to mitigate our exposure above assigned credit thresholds. We routinely exercise our contractual right to net realized gains against realized losses when settling with our financial counterparties. We may also be exposed to credit risk due to the concentration of our customers in the energy industry, as our customers may be similarly affected by prolonged changes in economic and industry conditions, or by the sale our oil and gas production to a limited number of purchasers.
49
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
50
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. Our internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and board of directors of the Company and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
We assessed the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (COSO). Based on our evaluation under the framework in Internal Control—Integrated Framework, we have concluded that our internal control over financial reporting was effective as of December 31, 2014. The effectiveness of our internal control over financial reporting as of December 31, 2014 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report included on page 54.
Management of Goodrich Petroleum Corporation
51
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Goodrich Petroleum Corporation
We have audited Goodrich Petroleum Corporation and subsidiary’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Goodrich Petroleum Corporation and subsidiary’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Goodrich Petroleum Corporation and subsidiary maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2014 consolidated financial statements of Goodrich Petroleum Corporation and subsidiary and our report dated February 27, 2015 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2015
52
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Goodrich Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Goodrich Petroleum Corporation and subsidiary as of December 31, 2014 and 2013, and the related consolidated statements of operations, cash flows, and stockholders’ equity, for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Goodrich Petroleum Corporation and subsidiary at December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Goodrich Petroleum Corporation and subsidiary’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 27, 2015 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2015
53
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
(In Thousands)
|
|
|
December 31, |
|
|||||
|
|
|
2014 |
|
|
2013 |
|
||
|
ASSETS |
|
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
8 |
|
|
$ |
49,220 |
|
|
Restricted cash |
|
|
— |
|
|
|
51,816 |
|
|
Accounts receivable, trade and other, net of allowance |
|
|
12,993 |
|
|
|
3,113 |
|
|
Accrued oil and natural gas revenue |
|
|
15,128 |
|
|
|
19,455 |
|
|
Fair value of oil and natural gas derivatives |
|
|
47,444 |
|
|
|
6,187 |
|
|
Inventory |
|
|
1,383 |
|
|
|
2,076 |
|
|
Prepaid expenses and other |
|
|
1,340 |
|
|
|
1,278 |
|
|
Total current assets |
|
|
78,296 |
|
|
|
133,145 |
|
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
|
|
|
|
Oil and natural gas properties (successful efforts method) |
|
|
1,478,042 |
|
|
|
1,838,220 |
|
|
Furniture, fixtures and equipment |
|
|
7,645 |
|
|
|
6,960 |
|
|
|
|
|
1,485,687 |
|
|
|
1,845,180 |
|
|
Less: Accumulated depletion, depreciation and amortization |
|
|
(871,082 |
) |
|
|
(1,021,863 |
) |
|
Net property and equipment |
|
|
614,605 |
|
|
|
823,317 |
|
|
Fair value of oil and natural gas derivatives |
|
|
— |
|
|
|
1,396 |
|
|
Deferred tax assets |
|
|
16,488 |
|
|
|
665 |
|
|
Deferred financing cost and other |
|
|
12,749 |
|
|
|
15,690 |
|
|
TOTAL ASSETS |
|
$ |
722,138 |
|
|
$ |
974,213 |
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT) |
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
86,823 |
|
|
$ |
50,551 |
|
|
Accrued liabilities |
|
|
54,143 |
|
|
|
48,603 |
|
|
Accrued abandonment costs |
|
|
145 |
|
|
|
99 |
|
|
Deferred tax liabilities current |
|
|
16,488 |
|
|
|
665 |
|
|
Fair value of oil and natural gas derivatives |
|
|
102 |
|
|
|
4,341 |
|
|
Current portion of debt |
|
|
— |
|
|
|
49,663 |
|
|
Total current liabilities |
|
|
157,701 |
|
|
|
153,922 |
|
|
Long term debt |
|
|
568,625 |
|
|
|
435,866 |
|
|
Accrued abandonment costs |
|
|
6,365 |
|
|
|
20,757 |
|
|
Fair value of oil and natural gas derivatives |
|
|
464 |
|
|
|
2,371 |
|
|
Transportation obligation |
|
|
4,127 |
|
|
|
4,774 |
|
|
Other non-current liability |
|
|
630 |
|
|
|
— |
|
|
Total liabilities |
|
|
737,912 |
|
|
|
617,690 |
|
|
Commitments and contingencies (See Note 9) |
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’ EQUITY: |
|
|
|
|
|
|
|
|
|
Preferred stock: 10,000,000 shares $1.00 par value authorized: |
|
|
|
|
|
|
|
|
|
Series B convertible preferred stock, issued and outstanding 2,250,000 |
|
|
2,250 |
|
|
|
2,250 |
|
|
Series C cumulative preferred stock, issued and outstanding 4,400 |
|
|
4 |
|
|
|
4 |
|
|
Series D cumulative preferred stock, issued and outstanding 5,200 |
|
|
5 |
|
|
|
5 |
|
|
Common stock: $0.20 par value, 100,000,000 shares authorized, issued and outstanding 45,105,205 and 44,258,824 shares, respectively |
|
|
9,021 |
|
|
|
8,852 |
|
|
Additional paid in capital |
|
|
1,066,770 |
|
|
|
1,056,378 |
|
|
Retained earnings (accumulated deficit) |
|
|
(1,093,824 |
) |
|
|
(710,966 |
) |
|
Total stockholders’ equity/(deficit) |
|
|
(15,774 |
) |
|
|
356,523 |
|
|
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT) |
|
$ |
722,138 |
|
|
$ |
974,213 |
|
See accompanying notes to consolidated financial statements.
54
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Amounts)
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
REVENUES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
208,544 |
|
|
$ |
202,557 |
|
|
$ |
180,543 |
|
|
Other |
|
|
9 |
|
|
|
738 |
|
|
|
302 |
|
|
|
|
|
208,553 |
|
|
|
203,295 |
|
|
|
180,845 |
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
29,525 |
|
|
|
27,293 |
|
|
|
25,938 |
|
|
Production and other taxes |
|
|
9,905 |
|
|
|
9,812 |
|
|
|
8,115 |
|
|
Transportation and processing |
|
|
9,070 |
|
|
|
10,498 |
|
|
|
13,900 |
|
|
Depreciation, depletion and amortization |
|
|
135,716 |
|
|
|
135,357 |
|
|
|
141,222 |
|
|
Exploration |
|
|
6,206 |
|
|
|
22,774 |
|
|
|
23,122 |
|
|
Impairment |
|
|
331,931 |
|
|
|
— |
|
|
|
47,818 |
|
|
General and administrative |
|
|
33,728 |
|
|
|
34,069 |
|
|
|
28,930 |
|
|
(Gain) loss on sale of assets |
|
|
3,499 |
|
|
|
(107 |
) |
|
|
(44,606 |
) |
|
Other |
|
|
3,793 |
|
|
|
(91 |
) |
|
|
91 |
|
|
|
|
|
563,373 |
|
|
|
239,605 |
|
|
|
244,530 |
|
|
Operating loss |
|
|
(354,820 |
) |
|
|
(36,310 |
) |
|
|
(63,685 |
) |
|
OTHER INCOME (EXPENSE): |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(47,829 |
) |
|
|
(51,187 |
) |
|
|
(52,403 |
) |
|
Interest income and other |
|
|
90 |
|
|
|
101 |
|
|
|
4 |
|
|
Gain (loss) on derivatives not designated as hedges |
|
|
49,423 |
|
|
|
(702 |
) |
|
|
31,882 |
|
|
Loss on extinguishment of debt |
|
|
— |
|
|
|
(7,088 |
) |
|
|
— |
|
|
|
|
|
1,684 |
|
|
|
(58,876 |
) |
|
|
(20,517 |
) |
|
Loss before income taxes |
|
|
(353,136 |
) |
|
|
(95,186 |
) |
|
|
(84,202 |
) |
|
Income tax benefit |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Net loss |
|
|
(353,136 |
) |
|
|
(95,186 |
) |
|
|
(84,202 |
) |
|
Preferred stock dividends |
|
|
29,722 |
|
|
|
18,604 |
|
|
|
6,047 |
|
|
Net loss applicable to common stock |
|
$ |
(382,858 |
) |
|
$ |
(113,790 |
) |
|
$ |
(90,249 |
) |
|
PER COMMON SHARE |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss applicable to common stock—basic |
|
$ |
(8.62 |
) |
|
$ |
(2.99 |
) |
|
$ |
(2.48 |
) |
|
Net loss applicable to common stock—diluted |
|
$ |
(8.62 |
) |
|
$ |
(2.99 |
) |
|
$ |
(2.48 |
) |
|
Weighted average common shares outstanding—basic |
|
|
44,402 |
|
|
|
38,098 |
|
|
|
36,390 |
|
|
Weighted average common shares outstanding—diluted |
|
|
44,402 |
|
|
|
38,098 |
|
|
|
36,390 |
|
See accompanying notes to consolidated financial statements.
55
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(353,136 |
) |
|
$ |
(95,186 |
) |
|
$ |
(84,202 |
) |
|
Adjustments to reconcile net loss to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
135,716 |
|
|
|
135,357 |
|
|
|
141,222 |
|
|
(Gain) loss on derivatives not designated as hedges |
|
|
(49,423 |
) |
|
|
702 |
|
|
|
(31,882 |
) |
|
Net cash received (paid) in settlement of derivative instruments |
|
|
3,417 |
|
|
|
(3,786 |
) |
|
|
73,160 |
|
|
Impairment |
|
|
331,931 |
|
|
|
— |
|
|
|
47,818 |
|
|
Exploration costs |
|
|
785 |
|
|
|
4,728 |
|
|
|
12,848 |
|
|
Amortization of leasehold costs |
|
|
3,108 |
|
|
|
13,675 |
|
|
|
5,948 |
|
|
Share based compensation (non-cash) |
|
|
9,555 |
|
|
|
7,680 |
|
|
|
6,903 |
|
|
(Gain) loss on sale of assets |
|
|
3,499 |
|
|
|
(107 |
) |
|
|
(44,606 |
) |
|
Loss on extinguishment of debt |
|
|
— |
|
|
|
7,088 |
|
|
|
— |
|
|
Amortization of finance cost and debt discount |
|
|
9,979 |
|
|
|
12,745 |
|
|
|
12,819 |
|
|
Amortization of transportation obligation |
|
|
804 |
|
|
|
1,226 |
|
|
|
1,457 |
|
|
Change in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, trade and other, net of allowance |
|
|
(9,881 |
) |
|
|
3,965 |
|
|
|
580 |
|
|
Income taxes receivable/payable |
|
|
— |
|
|
|
— |
|
|
|
277 |
|
|
Accrued oil and natural gas revenue |
|
|
3,540 |
|
|
|
(401 |
) |
|
|
1,399 |
|
|
Inventory |
|
|
693 |
|
|
|
126 |
|
|
|
6,415 |
|
|
Prepaid expenses and other |
|
|
1,279 |
|
|
|
386 |
|
|
|
3,356 |
|
|
Accounts payable |
|
|
35,694 |
|
|
|
(22,543 |
) |
|
|
26,999 |
|
|
Accrued liabilities |
|
|
(5,829 |
) |
|
|
5,750 |
|
|
|
(6,722 |
) |
|
Net cash provided by operating activities |
|
|
121,731 |
|
|
|
71,405 |
|
|
|
173,789 |
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(322,352 |
) |
|
|
(251,103 |
) |
|
|
(252,416 |
) |
|
Proceeds from sale of assets |
|
|
53,932 |
|
|
|
449 |
|
|
|
90,922 |
|
|
Net cash used in investing activities |
|
|
(268,420 |
) |
|
|
(250,654 |
) |
|
|
(161,494 |
) |
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal payments of bank borrowings |
|
|
(255,000 |
) |
|
|
(382,800 |
) |
|
|
(132,000 |
) |
|
Proceeds from bank borrowings |
|
|
376,000 |
|
|
|
287,800 |
|
|
|
124,500 |
|
|
Proceeds from preferred stock offering |
|
|
— |
|
|
|
230,625 |
|
|
|
— |
|
|
Proceeds from equity offering |
|
|
— |
|
|
|
166,149 |
|
|
|
— |
|
|
Repurchase of convertible notes |
|
|
(45,124 |
) |
|
|
— |
|
|
|
— |
|
|
Debt issuance costs |
|
|
(649 |
) |
|
|
(4,636 |
) |
|
|
(66 |
) |
|
Preferred stock dividends |
|
|
(29,722 |
) |
|
|
(18,604 |
) |
|
|
(6,047 |
) |
|
Cash restricted for repurchase of convertible notes |
|
|
51,816 |
|
|
|
(51,816 |
) |
|
|
— |
|
|
Exercise of stock options and warrants |
|
|
140 |
|
|
|
807 |
|
|
|
16 |
|
|
Other |
|
|
16 |
|
|
|
(244 |
) |
|
|
(857 |
) |
|
Net cash provided by (used in) financing activities |
|
|
97,477 |
|
|
|
227,281 |
|
|
|
(14,454 |
) |
|
Increase (decrease) in cash and cash equivalents |
|
|
(49,212 |
) |
|
|
48,032 |
|
|
|
(2,159 |
) |
|
Cash and cash equivalents, beginning of period |
|
|
49,220 |
|
|
|
1,188 |
|
|
|
3,347 |
|
|
Cash and cash equivalents, end of period |
|
$ |
8 |
|
|
$ |
49,220 |
|
|
$ |
1,188 |
|
|
Supplemental disclosures of cash flow information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for interest |
|
$ |
39,169 |
|
|
$ |
38,087 |
|
|
$ |
39,516 |
|
|
Cash paid during the year for taxes |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
See accompanying notes to consolidated financial statements.
56
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT)
(In Thousands)
|
|
|
Preferred Stock |
|
|
Common Stock |
|
|
Additional Paid-in |
|
|
Treasury Stock |
|
|
Retained Earnings/ |
|
|
Total Stockholders’ |
|
||||||||||||||||||
|
|
|
Shares |
|
|
Value |
|
|
Shares |
|
|
Value |
|
|
Capital |
|
|
Shares |
|
|
Value |
|
|
(Deficit) |
|
|
Equity/(Deficit) |
|
|||||||||
|
Balance at January 1, 2012 |
|
|
2,250 |
|
|
$ |
2,250 |
|
|
|
36,379 |
|
|
$ |
7,276 |
|
|
$ |
641,790 |
|
|
|
(45 |
) |
|
$ |
(689 |
) |
|
$ |
(506,927 |
) |
|
$ |
143,700 |
|
|
Net loss |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(84,202 |
) |
|
|
(84,202 |
) |
|
Employee stock plans |
|
|
— |
|
|
|
— |
|
|
|
386 |
|
|
|
77 |
|
|
|
6,826 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
6,903 |
|
|
Director stock grants |
|
|
— |
|
|
|
— |
|
|
|
57 |
|
|
|
11 |
|
|
|
721 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
732 |
|
|
Repurchases of stock |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(100 |
) |
|
|
(857 |
) |
|
|
— |
|
|
|
(857 |
) |
|
Options Exercised |
|
|
— |
|
|
|
— |
|
|
|
4 |
|
|
|
1 |
|
|
|
15 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
16 |
|
|
Retirement of stock |
|
|
— |
|
|
|
— |
|
|
|
(68 |
) |
|
|
(13 |
) |
|
|
(894 |
) |
|
|
68 |
|
|
|
907 |
|
|
|
— |
|
|
|
— |
|
|
Dividends |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(6,047 |
) |
|
|
(6,047 |
) |
|
Balance at December 31, 2012 |
|
|
2,250 |
|
|
$ |
2,250 |
|
|
|
36,758 |
|
|
$ |
7,352 |
|
|
$ |
648,458 |
|
|
|
(77 |
) |
|
$ |
(639 |
) |
|
$ |
(597,176 |
) |
|
$ |
60,245 |
|
|
Net loss |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(95,186 |
) |
|
|
(95,186 |
) |
|
Equity portion of convertible notes redeemed |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,398 |
|
|
Employee stock plans |
|
|
— |
|
|
|
— |
|
|
|
594 |
|
|
|
119 |
|
|
|
7,561 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
7,680 |
|
|
Director stock grants |
|
|
— |
|
|
|
— |
|
|
|
47 |
|
|
|
9 |
|
|
|
637 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
646 |
|
|
Repurchases of stock |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(3 |
) |
|
|
(74 |
) |
|
|
— |
|
|
|
(74 |
) |
|
Options Exercised |
|
|
— |
|
|
|
— |
|
|
|
41 |
|
|
|
8 |
|
|
|
799 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
807 |
|
|
Preferred Stock Offering |
|
|
9 |
|
|
|
9 |
|
|
|
— |
|
|
|
— |
|
|
|
230,616 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
230,625 |
|
|
Equity Offering |
|
|
— |
|
|
|
— |
|
|
|
6,900 |
|
|
|
1,380 |
|
|
|
164,769 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
166,149 |
|
|
Retirement of stock |
|
|
— |
|
|
|
— |
|
|
|
(81 |
) |
|
|
(16 |
) |
|
|
(697 |
) |
|
|
80 |
|
|
|
713 |
|
|
|
— |
|
|
|
— |
|
|
Other |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(163 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(163 |
) |
|
Dividends |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(18,604 |
) |
|
|
(18,604 |
) |
|
Balance at December 31, 2013 |
|
|
2,259 |
|
|
$ |
2,259 |
|
|
|
44,259 |
|
|
$ |
8,852 |
|
|
$ |
1,056,378 |
|
|
|
— |
|
|
$ |
— |
|
|
$ |
(710,966 |
) |
|
$ |
356,523 |
|
|
Net loss |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(353,136 |
) |
|
|
(353,136 |
) |
|
Employee stock plans |
|
|
— |
|
|
|
— |
|
|
|
802 |
|
|
|
160 |
|
|
|
9,395 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
9,555 |
|
|
Director stock grants |
|
|
— |
|
|
|
— |
|
|
|
38 |
|
|
|
8 |
|
|
|
858 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
866 |
|
|
Options Exercised |
|
|
— |
|
|
|
— |
|
|
|
6 |
|
|
|
1 |
|
|
|
139 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
140 |
|
|
Dividends |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(29,722 |
) |
|
|
(29,722 |
) |
|
Balance at December 31, 2014 |
|
|
2,259 |
|
|
$ |
2,259 |
|
|
|
45,105 |
|
|
$ |
9,021 |
|
|
$ |
1,066,770 |
|
|
|
— |
|
|
$ |
— |
|
|
$ |
(1,093,824 |
) |
|
$ |
(15,774 |
) |
See accompanying notes to consolidated financial statements.
57
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—Description of Business and Accounting Policies
Goodrich Petroleum Corporation (together with its subsidiary, “we,” “our,” or the “Company”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale (“TMS”), (ii) South Texas, which includes the Eagle Ford Shale Trend, and (iii) Northwest Louisiana and East Texas, which includes the Haynesville Shale.
Liquidity and Capital Resources—We are an exploration and production Company with interests in non-conventional oil shale properties that require large investments of capital to develop. Our immediate capital resources to develop our properties come from cash on hand, operating cash flows and borrowings on our Senior Credit Facility. The current significant decline in crude oil prices and to a lesser extent the continued depressed natural gas prices has negatively impacted our cash flows that enable us to invest in and maintain our properties and service our long term obligations.
We have in place at December 31, 2014 or have subsequently taken the following steps to mitigate the effects of the abnormally low crude oil prices on our operations:
1. We have significantly reduced our capital expenditures planned for 2015 thereby conserving capital.
2. We have extended the maturity of our Senior Credit Facility to February 24, 2017.
3. We have approximately 70% of our projected 2015 oil production favorably hedged.
4. On February 26, 2015 we entered into a definitive agreement to issue $100 million of second lien senior secured notes (see Note 12).
We have other resource options to enhance liquidity as well, such as selling non-core properties, entering into joint venture in our core areas and/or further reducing our planned capital expenditures.
As a result of the steps we have taken to enhance our liquidity, we anticipate cash from operations, cash on hand and available borrowing capacity will be sufficient to meet the our investing, financing, and working capital requirements through the end of 2015, however we cannot predict the effect an extended period of low commodity prices will have on the Company.
Principles of Consolidation—The consolidated financial statements of the Company are included in this Annual Report on Form 10-K have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) and in accordance with accounting principles generally accepted in the United States (“US GAAP”). The consolidated financial statements include the financial statements of Goodrich Petroleum Corporation and its wholly-owned subsidiary. Intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Certain data in prior periods’ financial statements have been adjusted to conform to the presentation of the current period. We have evaluated subsequent events through the date of this filing.
Use of Estimates—Our Management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with US GAAP.
Cash and Cash Equivalents—Cash and cash equivalents include cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at date of purchase.
Restricted Cash—Restricted cash at December 31, 2013 of $51.8 million was held in escrow for the repurchase of the remaining outstanding principal amount on our 5% Convertible Senior Notes due 2029. See Note 4.
Allowance for Doubtful Accounts—We routinely assess the recoverability of all material trade and other receivables to determine their collectability. Many of our receivables are from a limited number of purchasers. Accordingly, accounts receivable from such purchases could be significant. Generally, our natural gas and crude oil receivables are collected within thirty to sixty days of production. We also have receivables from joint interest owners of properties we operate. We may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
58
We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. As of each of December 31, 2014 and 2013, we had no allowance for doubtful accounts.
Inventory –Inventory consists of casing and tubulars that are expected to be used in our capital drilling program and oil in storage tanks. Inventory is carried on the Consolidated Balance Sheets at the lower of cost or market.
Property and Equipment—We follow the successful efforts method of accounting for exploration and development expenditures. Under this method, costs of acquiring unproved and proved oil and natural gas leasehold acreage are capitalized. When proved reserves are found on an unproved property, the associated leasehold cost is transferred to proved properties. Significant unproved leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. Costs of all other unproved leases are amortized over the estimated average holding period of the leases. Development costs are capitalized, including the costs of unsuccessful development wells.
Exploration—Exploration expenditures, including geological and geophysical costs, delay rentals and exploratory dry hole costs are expensed as incurred. Costs of drilling exploratory wells are initially capitalized pending determination of whether proved reserves can be attributed to the discovery. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are expensed. We have $14.5 million of capitalized exploratory well costs that are pending the determination of proved reserves as of December 31, 2014 and had $9.7 million as of December 31, 2013. During 2014, none of the December 31, 2013 pending capitalized exploratory well costs were expensed. .
Fair Value Measurement— Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, our credit risk.
We use various methods, including the income approach and market approach, to determine the fair values of our financial instruments that are measured at fair value on a recurring basis, which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For some of our instruments, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For other instruments, the fair value may be calculated based on these inputs as well as other assumptions related to estimates of future settlements of these instruments. We separate our financial instruments into three levels (levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between levels.
Each of these levels and our corresponding instruments classified by level are further described below:
|
· |
Level 1 Inputs— unadjusted quoted market prices in active markets for identical assets or liabilities. Included in this level is our Senior Notes; |
|
· |
Level 2 Inputs—quotes which are derived principally from or corroborated by observable market data. Included in this level are our Senior Credit Facility and commodity derivatives whose fair values are based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counterparties; and |
|
· |
Level 3 Inputs—unobservable inputs for the asset or liability, such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices. Included in this level are our oil and natural gas properties which are deemed impaired. |
59
As of December 31, 2014 and 2013, the carrying amounts of our cash and cash equivalents, trade receivables and payables represented fair value because of the short-term nature of these instruments.
|
|
Fair Value Measurements as of December 31, 2014 |
|
||||||||||||
|
|
(in thousands) |
|
||||||||||||
|
Description |
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
Total |
|
||||
|
Recurring Fair Value Measurements |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives (see Note 8) |
$ |
— |
|
|
$ |
46,878 |
|
|
$ |
— |
|
$ |
46,878 |
|
|
Debt (see Note 4) |
|
(227,051 |
) |
|
|
(121,000 |
) |
|
|
— |
|
|
(348,051 |
) |
|
Total recurring fair value measurements |
$ |
(227,051 |
) |
|
$ |
(74,122 |
) |
|
$ |
— |
|
$ |
(301,173 |
) |
|
Nonrecurring Fair Value Measurements |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impaired oil and natural gas properties |
$ |
— |
|
|
$ |
— |
|
|
$ |
61,613 |
|
$ |
61,613 |
|
Impairment —We periodically assess our long-lived assets recorded in oil and natural gas properties on the Consolidated Balance Sheets to ensure that they are not carried in excess of fair value, which is computed using level 3 inputs such as discounted cash flow models or valuations. Significant level 3 assumptions associated with discounted cash flow models or valuations used in the impairment evaluation include estimates of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. An evaluation is performed on a field-by-field basis at least annually or whenever changes in facts and circumstances indicate that our oil and natural gas properties may be impaired.
As of December 31, 2014, we had interests in oil and natural gas properties totaling $613.1 million, net of accumulated depletion, which we account for under the successful efforts method. The expected future cash flows used for impairment reviews and related fair-value calculations are based on judgmental assessments of future production volumes, prices, and costs, considering all available information at the date of review. Due to the uncertainty inherent in these factors, we cannot predict when or if additional future impairment charges will be recorded. We estimate future net cash flows generated from our oil and natural gas properties using forecasted oil and natural gas prices published by the New York Mercantile Exchange (“NYMEX”).
During 2014, there was an indication, due to declines in commodity prices, that the carrying amount of certain of our oil and natural gas properties was not recoverable from future cash flows. As a result, we recorded impairments of $246.6 million in the fourth quarter of 2014. The impairment in 2014 reduced the carrying value of the impaired fields to an estimated fair value of $61.6 million as of December 31, 2014. We also recorded impairments of $85.3 million during the third quarter of 2014 for properties that were sold in December 2014. For the year ended December 31, 2013 we recorded no impairments.
Depreciation —Depreciation and depletion of producing oil and natural gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs.
Gains and losses on disposals or retirements that are significant or include an entire depreciable or depletable property unit are included in operating income. Depreciation of furniture, fixtures and equipment, consisting of office furniture, computer hardware and software and leasehold improvements, is computed using the straight-line method over their estimated useful lives, which vary from three to five years.
Transportation Obligation—We entered into a natural gas gathering agreement with an independent service provider, effective July 27, 2010. The agreement is scheduled to remain in effect for a period of ten years and requires the service provider to construct pipelines and facilities to connect our wells to the service provider’s gathering system in our Eagle Ford Shale Trend area of South Texas. In exchange for these services, we agreed to pay the service provider 110 percent of the total capital cost incurred by the service provider to construct new pipelines and facilities. The service provider bills us for 20 percent of the accumulated unpaid capital costs annually. The transportation obligation liability was $5.4 million and $6.3 million as of December 31, 2014 and 2013, respectively.
We accounted for the agreement by recording a long-term asset, included in “Deferred financing cost and other” on the Consolidated Balance Sheets. The asset is being amortized using the units-of-production method and the amortization expense is included in “Transportation and processing” on the Consolidated Statements of Operations. The related current and long-term liabilities are presented on the Consolidated Balance Sheets in “Accrued liabilities” and “Transportation obligation,” respectively.
60
Asset Retirement Obligations—Asset retirement obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense is included in “Depreciation, depletion and amortization” on our Consolidated Statements of Operations.
Revenue Recognition—Oil and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized using the entitlements method. We record a liability or an asset for natural gas balancing when we have sold more or less than our working interest share of natural gas production, respectively. At December 31, 2014 and 2013, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.
Derivative Instruments—We use derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates. Accounting standards related to derivative instruments and hedging activities require that all derivative instruments subject to the requirements of those standards be measured at fair value and recognized as assets or liabilities in the balance sheet. We offset the fair value of our asset and liability positions with the same counterparty for each commodity type. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. We have not designated any of our derivative contracts as hedges; accordingly, changes in fair value are reflected in earnings.
Income Taxes—We account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
We recognize, as required, the financial statement benefit of an uncertain tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority.
Earnings Per Share—Basic income or loss per common share is computed by dividing net income or loss available to common stockholders for each reporting period by the weighted-average number of common shares outstanding during the period. Diluted income or loss per common share is computed by dividing net income or loss available to common stockholders for each reporting period by the weighted average number of common shares outstanding during the period, plus the effects of potentially dilutive stock options and restricted stock calculated using the Treasury Stock method and the potential dilutive effect of the conversion of shares associated with 5.375% Series B Convertible Preferred Stock (“Series B Preferred Stock”), 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”), 5% Convertible Senior Notes due 2029 (the “2029 Notes”) and 5% Convertible Senior Notes due 2032 (the “2032 Notes”).
Commitments and Contingencies—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, when probable of realization, are separately recorded and are not offset against the related environmental liability.
Concentration of Credit Risk—Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2014, 2013 and 2012 are as follows:
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
BP Energy Company |
|
|
46% |
|
|
|
64% |
|
|
|
34% |
|
|
Genesis Crude Oil LP |
|
|
11% |
|
|
|
7% |
|
|
|
— |
|
|
Flint Hill Resources, LLC |
|
|
— |
|
|
|
— |
|
|
|
15% |
|
61
Share-Based Compensation—We account for our share-based transactions using fair value and recognize compensation expense over the requisite service period. The fair value of each option award is estimated using a Black-Scholes option valuation model with various assumptions based on our estimates. Our assumptions include expected volatility, expected term of option, risk-free interest rate and dividend yield. Expected volatility estimates are developed by us based on historical volatility of our stock. We use historical data to estimate the expected term of the options. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield in effect at the grant date. Our common stock does not pay dividends; therefore, the dividend yield is zero. The fair value of each restricted stock award is measured using the closing price of our common stock on the day of the award.
Guarantee—On March 2, 2011, we issued and sold $275 million aggregate principal amount of our 8.875% Senior Notes due 2019 (the “2019 Notes”). Upon issuance of the guarantee related to the 2019 Notes, our subsidiary also became a guarantor on our outstanding 2029 Notes and our 2026 Notes, pursuant to the respective indentures governing the 2029 Notes and 2026 Notes. On August 26, 2013 and October 1, 2013, we issued $109.25 million and $57.0 million, respectively, aggregate principal amount of our 2032 Notes, which are also guaranteed by our subsidiary pursuant to the terms of the indenture governing the 2032 Notes. The 2019 Notes, 2029 Notes, 2026 Notes and 2032 Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Goodrich Petroleum Company, L.L.C.
Goodrich Petroleum Corporation, as the parent company (the “Parent Company”), has no independent assets or operations. The guarantee is full and unconditional, subject to customary exceptions pursuant to the indenture governing our 2019 Notes, 2026 Notes, 2029 Notes and 2032 Notes, as discussed below. The Parent Company has no other subsidiaries. In addition, there are no restrictions on the ability of the Parent Company to obtain funds from its subsidiary by dividend or loan. Finally, the Parent Company’s wholly-owned subsidiary does not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by the subsidiary without the consent of a third party.
Guarantees of the 2019 Notes will be released under certain circumstances, including in the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of its capital stock or the sale of all or substantially all of its assets (other than by lease)) and whether or not the Subsidiary Guarantor is the surviving entity in such transaction to a person which is not the Parent Company or a Restricted Subsidiary of the Parent Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if the sale or other disposition does not violate the covenants described under “Limitation on Sales of Assets and Subsidiary Stock” in the indenture governing the 2019 Notes. In addition, a Subsidiary Guarantor will be released from its obligations under the indenture and its guarantee if such Subsidiary Guarantor ceases to guarantee any other indebtedness of the Parent Company or a Subsidiary Guarantor under a credit facility, and is not a borrower under the Senior Secured Credit Agreement, provided no Event of Default (as defined in the indenture governing the 2019 Notes) has occurred and is continuing; or if the Parent Company designates such subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the indenture or if such subsidiary otherwise no longer meets the definition of a Restricted Subsidiary; or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the 2019 Notes in accordance with the indenture.
Guarantees of the 2032 Notes, 2029 Notes and 2026 Notes will be released if the Subsidiary Guarantor no longer guarantees the 2019 Notes, if the Subsidiary Guarantor is dissolved or liquidated, if the Subsidiary Guarantor is no longer the Parent Company’s subsidiary or upon satisfaction and discharge of the 2032 Notes, 2029 Notes or 2026 Notes in accordance with their respective indentures.
New Accounting Pronouncements
On January 9, 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, which eliminates the concept of “extraordinary” items from US GAAP. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity also may apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on the Company’s consolidated financial statements.
On August 27, 2014, the FASB issued ASU 2014-15, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of the Company’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The ASU applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted.
62
In May 2014, the FASB issued ASU 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the new guidance to determine the impact it will have on its consolidated financial statements.
In April 2014, the FASB issued ASU 2014-08, which includes amendments that change the requirements for reporting discontinued operations and require additional disclosures about discontinued operations. Under the new guidance, only disposals representing a strategic shift in operations - that is, a major effect on the organization’s operations and financial results should be presented as discontinued operations. Additionally, the ASU requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income, and expenses of discontinued operations. The new standard is effective in the first quarter of 2015 for public organizations with calendar year ends. Early adoption would be permitted for any annual or interim period for which an entity’s financial statements have not yet been made available for issuance. The adoption of this guidance is not expected to have an impact on the Company’s consolidated financial statements.
NOTE 2—Share-Based Compensation Plans
Overview
At our annual meeting of stockholders in May 2006, our shareholders approved our 2006 Long-Term Incentive Plan (the “2006 Plan”). The 2006 Plan provides for grants to officers, employees and non-employee directors. Under the 2006 Plan as amended in 2014, a maximum of 6.3 million shares are authorized for issuance as awards of restricted stock and stock options. We had 1.9 million shares of granted but unvested restricted stock and 1.2 million shares were available for future grants as of December 31, 2014.
The 2006 Plan is intended to promote the interests of the Company by providing a means by which employees, consultants and directors may acquire or increase their equity interest in the Company and may develop a sense of proprietorship and personal involvement in the development and financial success of the Company, and to encourage them to remain with and devote their best efforts to the business of the Company, thereby advancing the interests of the Company and its stockholders. The 2006 Plan is also intended to enhance the ability of the Company and its Subsidiary to attract and retain the services of individuals who are essential for the growth and profitability of the Company.
The 2006 Plan provides that the Compensation Committee shall have the authority to determine the participants to whom stock options, restricted stock, performance awards, phantom shares and stock appreciation rights may be granted.
We measure the cost of stock based compensation granted, including stock options and restricted stock, based on the fair value of the award as of the grant date, net of estimated forfeitures. Awards granted are valued at fair value and recognized on a straight-line basis over the service periods (or the vesting periods) of each award. We estimate forfeiture rates for all unvested awards based on our historical experience.
The following table summarizes the pretax components of our share-based compensation programs recorded, recognized as a component of general and administrative expenses in the Consolidated Statements of Operations (in thousands):
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
Restricted stock expense |
|
$ |
9,555 |
|
|
$ |
7,586 |
|
|
$ |
6,670 |
|
|
Stock option expense |
|
|
— |
|
|
|
94 |
|
|
|
233 |
|
|
Director stock expense |
|
|
734 |
|
|
|
568 |
|
|
|
585 |
|
|
Total share-based compensation: |
|
$ |
10,289 |
|
|
$ |
8,248 |
|
|
$ |
7,488 |
|
Stock Options
The 2006 Plan provides that the option price of shares issued be equal to the market price on the date of grant. With the exception of option grants to non-employee directors, which vest immediately, options vest ratably on the anniversary of the date of grant over a period of time, typically three years. Our stock options expire in seven or ten years after the date of grant.
63
Option activity under our stock option plans as of December 31, 2014, and changes during the year ended December 31, 2014 were as follows:
|
|
|
Shares |
|
|
Weighted Average Exercise Price |
|
|
Remaining Contractual Term |
|
|
Aggregate Intrinsic Value |
|
||||
|
|
|
|
|
|
|
|
|
|
|
(years) |
|
|
(thousands) |
|
||
|
Outstanding at January 1, 2014 |
|
|
854,634 |
|
|
$ |
21.64 |
|
|
|
1.84 |
|
|
$ |
88 |
|
|
Granted |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Exercised |
|
|
6,500 |
|
|
|
21.59 |
|
|
|
— |
|
|
|
— |
|
|
Forfeited |
|
|
157,300 |
|
|
|
16.46 |
|
|
|
— |
|
|
|
— |
|
|
Outstanding at December 31, 2014 |
|
|
690,834 |
|
|
$ |
22.82 |
|
|
|
1.02 |
|
|
|
— |
|
|
Exercisable at December 31, 2014 |
|
|
690,834 |
|
|
$ |
22.82 |
|
|
|
1.02 |
|
|
|
— |
|
The aggregate intrinsic value in the preceding table represents the total pre-tax intrinsic value (the difference between our closing stock price on the last trading day of the fourth quarter of 2014 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2014. The amount of aggregate intrinsic value will change based on the fair market value of our stock. The total intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was less than $0.3 million. The outstanding options had no intrinsic value as of December 31, 2014.
|
|
|
Options Outstanding |
|
|
Options Exercisable |
|
||||||||||||||
|
Range of Exercise Prices |
|
Number Outstanding at December 31, 2014 |
|
|
Weighted Average Remaining Contractual Life |
|
|
Weighted Average Exercise Price |
|
|
Number Exercisable at December 31, 2014 |
|
|
Weighted Average Exercise Price |
|
|||||
|
|
|
|
|
|
|
(years) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$19.78 |
|
|
150,000 |
|
|
|
0.24 |
|
|
|
19.78 |
|
|
|
150,000 |
|
|
|
19.78 |
|
|
$21.59 to $27.81 |
|
|
540,834 |
|
|
|
1.24 |
|
|
|
23.67 |
|
|
|
540,834 |
|
|
|
23.67 |
|
|
|
|
|
690,834 |
|
|
|
1.02 |
|
|
|
22.82 |
|
|
|
690,834 |
|
|
|
22.82 |
|
As of December 31, 2014, all compensation cost related to the stock options has been recognized in earnings. No stock options were granted in 2014, 2013 or 2012.
Restricted Stock
In 2003, we began granting a series of restricted stock awards. Restricted stock awarded under the 2006 Plan typically has a vesting period of three years. During the vesting period, ownership of the shares cannot be transferred and the shares are subject to forfeiture if employment ends before the end of the vesting period. Certain restricted stock awards provide for accelerated vesting. Restricted shares are not considered to be currently issued and outstanding until the restrictions lapse and/or they vest.
Restricted stock activity and values under our plan for the years ended December 31, 2014, 2013 and 2012 were as follows:
|
|
|
Number of Shares Granted |
|
|
Value of Shares Granted |
|
|
Fair Value of Stock Vested |
|
|||
|
|
|
|
|
|
|
(thousands) |
|
|
(thousands) |
|
||
|
2014 |
|
|
1,192,114 |
|
|
$ |
5,368 |
|
|
$ |
6,425 |
|
|
2013 |
|
|
746,163 |
|
|
|
13,194 |
|
|
|
9,960 |
|
|
2012 |
|
|
1,073,727 |
|
|
|
9,533 |
|
|
|
3,335 |
|
64
Restricted stock activity under our plan for the year ended December 31, 2014, and changes during the year then ended were as follows:
|
|
|
Number of Shares |
|
|
Weighted Average Grant-Date Fair Value |
|
|
Total Value |
|
|||
|
|
|
|
|
|
|
|
|
|
|
(thousands) |
|
|
|
Unvested at January 1, 2014 |
|
|
1,581,207 |
|
|
$ |
13.58 |
|
|
$ |
21,476 |
|
|
Vested |
|
|
(801,865 |
) |
|
|
13.02 |
|
|
|
(10,430 |
) |
|
Granted |
|
|
1,192,114 |
|
|
|
4.50 |
|
|
|
5,368 |
|
|
Forfeited |
|
|
(31,516 |
) |
|
|
12.56 |
|
|
|
(396 |
) |
|
Unvested at December 31, 2014 |
|
|
1,939,940 |
|
|
|
— |
|
|
$ |
16,018 |
|
As of December 31, 2014, total unrecognized compensation cost related to restricted stock is as follows:
|
|
|
Unrecognized compensation costs |
|
|
Weighted Average years to recognition |
|
||
|
|
|
(thousands) |
|
|
(years) |
|
||
|
December 31, 2014 |
|
$ |
15,354 |
|
|
|
1.93 |
|
NOTE 3—Asset Retirement Obligations
The reconciliation of the beginning and ending asset retirement obligation for the periods ending December 31, 2014 and 2013 is as follows (in thousands):
|
|
|
December 31, |
|
|||||
|
|
|
2014 |
|
|
2013 |
|
||
|
Beginning balance |
|
$ |
20,856 |
|
|
$ |
18,306 |
|
|
Liabilities incurred |
|
|
385 |
|
|
|
471 |
|
|
Revisions in estimated liabilities |
|
|
53 |
|
|
|
1,290 |
|
|
Liabilities settled |
|
|
(5 |
) |
|
|
(82 |
) |
|
Accretion expense |
|
|
1,420 |
|
|
|
1,243 |
|
|
Dispositions (1) |
|
|
(16,199 |
) |
|
|
(372 |
) |
|
Ending balance |
|
$ |
6,510 |
|
|
$ |
20,856 |
|
|
Current liability |
|
$ |
145 |
|
|
$ |
99 |
|
|
Long term liability |
|
$ |
6,365 |
|
|
$ |
20,757 |
|
|
(1) |
The majority of the 2014 dispositions represent the divestiture of our East Texas properties. |
NOTE 4—Debt
Debt consisted of the following balances as of the dates indicated (in thousands):
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
||||||||||||||||||
|
|
|
Principal |
|
|
Carrying Amount |
|
|
Fair Value (1) |
|
|
Principal |
|
|
Carrying Amount |
|
|
Fair Value (1) |
|
||||||
|
Senior Credit Facility (1) |
|
$ |
121,000 |
|
|
$ |
121,000 |
|
|
$ |
121,000 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
3.25% Convertible Senior Notes due 2026 |
|
|
429 |
|
|
|
429 |
|
|
|
353 |
|
|
|
429 |
|
|
|
429 |
|
|
|
429 |
|
|
5.0% Convertible Senior Notes due 2029 (2) |
|
|
6,692 |
|
|
|
6,692 |
|
|
|
3,480 |
|
|
|
51,816 |
|
|
|
49,663 |
|
|
|
51,686 |
|
|
5.0% Convertible Senior Notes due 2032 (3) |
|
|
170,770 |
|
|
|
165,504 |
|
|
|
87,093 |
|
|
|
167,405 |
|
|
|
160,437 |
|
|
|
171,863 |
|
|
8.875% Senior Notes due 2019 |
|
|
275,000 |
|
|
|
275,000 |
|
|
|
136,125 |
|
|
|
275,000 |
|
|
|
275,000 |
|
|
|
288,063 |
|
|
Total debt |
|
$ |
573,891 |
|
|
$ |
568,625 |
|
|
$ |
348,051 |
|
|
$ |
494,650 |
|
|
$ |
485,529 |
|
|
$ |
512,041 |
|
65
|
(1) |
The carrying amount for the Second Amended and Restated Credit Agreement represents fair value as the variable interest rates are reflective of current market conditions. The fair value of the notes was obtained by direct market quotes within Level 1 of the fair value hierarchy. |
|
(2) |
The debt discount was amortized using the effective interest rate method based upon an original five year term through October 1, 2014. The debt discount was zero and $2.1 million as of December 31, 2014 and December 31, 2013, respectively. |
|
(3) |
The debt discount is amortized using the effective interest rate method based upon a four year term through October 1, 2017, the first repurchase date applicable to the 2032 Notes. The debt discount was $5.3 million and $7.0 million as of December 31, 2014 and December 31, 2013, respectively. |
The following table summarizes the total interest expense for the years ended (contractual interest expense, amortization of debt discount and financing costs) and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates) for the years ended:
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
|
December 31, 2012 |
|
|||||||||||||||
|
|
|
Interest Expense |
|
|
Effective Interest Rate |
|
|
Interest Expense |
|
|
Effective Interest Rate |
|
|
Interest Expense |
|
|
Effective Interest Rate |
|
||||||
|
Senior Credit Facility (1) |
|
$ |
3,943 |
|
|
|
5.2% |
|
|
$ |
3,936 |
|
|
|
5.3% |
|
|
$ |
5,114 |
|
|
|
3.7% |
|
|
3.25% Convertible Senior Notes due 2026 |
|
|
14 |
|
|
|
3.3% |
|
|
|
14 |
|
|
|
3.3% |
|
|
|
14 |
|
|
|
3.3% |
|
|
5.0% Convertible Senior Notes due 2029 |
|
|
4,363 |
|
|
|
11.0% |
|
|
|
17,400 |
|
|
|
11.4% |
|
|
|
21,968 |
|
|
|
11.4% |
|
|
5.0% Convertible Senior Notes due 2032(1) |
|
|
14,201 |
|
|
|
8.7% |
|
|
|
4,529 |
|
|
|
8.8% |
|
|
|
— |
|
|
|
— |
|
|
8.875% Senior Notes due 2019 (1) |
|
|
25,308 |
|
|
|
9.2% |
|
|
|
25,308 |
|
|
|
9.2% |
|
|
|
25,308 |
|
|
|
9.2% |
|
|
(1) |
Deferred financing costs are amortized using the straight-line method through the contractual maturity dates for the Senior Credit Facility and 2019 Notes and through the first put date of October 1, 2017 for the 2032 Notes. |
Senior Credit Facility
Total lender commitments under the Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”) are $600 million subject to borrowing base limitation, which as of December 31, 2014 was $230 million. Pursuant to the terms of the Senior Credit Facility borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. As of December 31, 2014, we had $121.0 million outstanding under the Senior Credit Facility. In February 2015, we entered into the Thirteenth Amendment with an effective date of February 26, 2015. On the effective date, the Thirteenth Amendment reduced our borrowing base to $200 million and, extended the maturity of the Senior Credit Facility to February 24, 2017. On February 26, 2015 we entered into a definitive agreement to issue $100 million of second lien senior secured notes, which will be used to pay down the amount drawn on our Senior Credit Facility. Our borrowing base will be further reduced to $150 million upon the earlier of April 1, 2015 or the funding of the $100 million second lien senior secured notes. The next borrowing base redetermination will occur on October 1, 2015. Interest on revolving borrowings under the Senior Credit Facility, as amended, accrues at a rate calculated, at our option, at the bank base rate plus 1.25% to 2.25% or LIBOR plus 2.25% to 3.25%, depending on borrowing base utilization. Substantially all our assets are pledged as collateral to secure the Senior Credit Facility.
The terms of the Senior Credit Facility as amended by the Thirteenth Amendment, require us to maintain certain covenants. Capitalized terms used here, but not defined, have the meanings assigned to them in the Senior Credit Facility.. The primary financial covenants include:
|
· |
Current Ratio of 1.0/1.0; |
|
· |
Interest Coverage Ratio of EBITDAX of not less than 2.0/1.0 for the trailing four quarters EBITDAX. The interest for such period to apply solely to the cash portion of interest expense; and |
|
· |
Maximum Secured Debt no greater than 2.5 times EBITDAX for the trailing four quarters. |
As used in connection with the Senior Credit Facility, Current Ratio is consolidated current assets (including current availability under the Senior Credit Facility, but excluding non-cash assets related to our derivatives) to consolidated current liabilities (excluding non-cash liabilities related to our derivatives, accrued capital expenditures and current maturities under the Senior Credit Facility).
As used in connection with the Senior Credit Facility, EBITDAX is earnings before interest expense, income tax, depreciation, depletion and amortization, exploration expense, stock based compensation and impairment of oil and natural gas properties. In calculating EBITDAX for this purpose, gains/losses on derivatives not designated as hedges, less net cash received (paid) in settlement of commodity derivatives are excluded from Adjusted EBITDAX.
66
We were in compliance with all the financial covenants of the Senior Credit Facility as of December 31, 2014 which on that date were:
|
· |
Current Ratio of 1.0/1.0; |
|
· |
Interest Coverage Ratio of EBITDAX of not less than 2.5/1.0 on an annualized basis when measured for the second, third and fourth quarters of 2014, shall be based on annualized interim EBITDAX amounts rather than trailing four quarters. The interest for such period to apply solely to the cash portion of interest expense; and |
|
· |
Total Debt no greater than 4.0 times EBITDAX for the trailing four quarters. Provided that such ratio, when measured for the third and fourth quarters of 2014 shall be based on annualized interim EBITDAX amounts rather than trailing four quarters. |
8.875% Senior Notes due 2019
On March 2, 2011, we sold $275 million of our 2019 Notes. The 2019 Notes mature on March 15, 2019, unless earlier redeemed or repurchased. The 2019 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2019 Notes accrue interest at a rate of 8.875% annually, and interest is paid semi-annually in arrears on March 15 and September 15. The 2019 Notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility.
After March 15, 2015, we may redeem all or a portion of the 2019 Notes at redemption prices (expressed as percentages of principal amount) equal to (i) 104.438% for the twelve-month period beginning on March 15, 2015; (ii) 102.219% for the twelve-month period beginning on March 15, 2016 and (iii) 100.000% on or after March 15, 2017, in each case plus accrued and unpaid interest to the redemption date. In addition, prior to March 15, 2015, we may redeem all or a part of the 2019 Notes at a redemption price equal to 100% of the principal amount of the 2019 Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest to the redemption date.
The indenture governing the 2019 Notes restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem or retire such capital stock; (iii) sell assets, including the capital stock of our restricted subsidiaries; (iv) pay dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. These covenants are subject to a number of important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indenture governing the 2019 Notes) has occurred and is continuing, many of these covenants will terminate.
5% Convertible Senior Notes due 2029
In September 2009, we sold $218.5 million of our 2029 Notes. The 2029 Notes mature on October 1, 2029, unless earlier converted, redeemed or repurchased. As of December 31, 2014, $6.7 million in aggregate principal amount of the 2029 Notes remain outstanding.
The 2029 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2029 Notes accrue interest at a rate of 5% annually, and interest is paid semi-annually in arrears on April 1 and October 1 of each year.
We exchanged $166.7 million of 2029 Notes for 2032 Notes in 2013. On October 1, 2014, we repurchased $45.1 million of the 2029 Notes using the restricted cash held in escrow for that purpose.
The 2029 Notes are convertible into shares of our common stock at a rate equal to 28.8534 shares per $1,000 principal amount of 2029 Notes (equal to an initial conversion price of approximately $34.66 per share of common stock per share).
Investors may convert their 2029 Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances: (1) during any fiscal quarter (and only during such fiscal quarter), if the last reported sale price of our common stock is greater than or equal to 135% of the conversion price of the 2029 Notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter; (2) if the 2029 Notes have been called for redemption or (3) upon the occurrence of one of specified corporate transactions. Investors may also convert their 2029 Notes at their option at any time beginning on September 1, 2029, and ending at the close of business on the second business day immediately preceding the maturity date.
67
We separately accounted for the liability and equity components of our 2029 Notes in a manner that reflected our nonconvertible debt borrowing rate when interest was recognized through September 30, 2014. The debt discount was amortized using the effective interest rate method based upon an original five year term through October 1, 2014. The debt discount on the 2029 Notes was fully amortized as of December 31, 2014.
5% Convertible Senior Notes due 2032
We entered into separate, privately negotiated exchange agreements in 2013 under which we retired $166.7 million in aggregate principal amount of our outstanding 2029 Notes in exchange for the issuance of the 2032 Notes in an aggregate principal amount of $166.3 million. The 2032 Notes will mature on October 1, 2032.
Many terms of the 2032 Notes remain the same as the 2029 Notes they replaced, including the 5.0% annual cash interest rate and the conversion rate of 28.8534 shares of our common stock per $1,000 principal amount of 2032 Notes (equivalent to an initial conversion price of approximately $34.6580 per share of common stock), subject to adjustment in certain circumstances.
Unlike the 2029 Notes, the principal amount of the 2032 Notes accretes at a rate of 2% per year commencing August 26, 2013, compounding on a semi-annual basis, until October 1, 2017. The accreted portion of the principal is payable in cash upon maturity but does not bear cash interest and is not convertible into our common stock. Holders have the option to require us to purchase any outstanding 2032 Notes on each of October 1, 2017, 2022 and 2027, at a price equal to 100% of the principal amount plus the accretion thereon. Accretion of principal is and will be reflected as a non-cash component of interest expense on our consolidated statement of operations during the term of the 2032 Notes. We recorded $3.4 million of accretion during 2014.
We have the right to redeem the 2032 Notes on or after October 1, 2016 at a price equal to 100% of the principal amount, plus accrued but unpaid interest and accretion thereon. The 2032 Notes also provide us with the option, at our election, to convert the new notes in whole or in part, prior to maturity, into the underlying common stock, provided the trading price of our common stock exceeds $45.06 (or 130% of the then applicable conversion price) for the required measurement period. If we elect to convert the 2032 Notes on or before October 1, 2016, holders will receive a make-whole premium.
We separately account for the liability and equity components of our 2032 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. We measured the debt component of the 2032 Notes using an effective interest rate of 8%. We attributed $158.8 million of the fair value to the 2032 Note to debt component which compared to the face results in a debt discount of $7.5 million which will be amortized through the first put date of October 1, 2017. Additionally, we recorded $24.4 million within additional paid-in capital representing the equity component of the 2032 Notes. A debt discount of $5.3 million remains to be amortized on the 2032 Notes as of December 31, 2014.
3.25% Convertible Senior Notes Due 2026
At December 31, 2014, $0.4 million of the 2026 Notes remained outstanding. Holders may present to us for redemption the remaining outstanding 2026 Notes on December 1, 2016 and December 1, 2021.
Upon conversion, we have the option to deliver shares at the applicable conversion rate, redeem in cash or in certain circumstances redeem in a combination of cash and shares.
The 2026 Notes are convertible into shares of our common stock at a rate equal to the sum of:
|
a) |
15.1653 shares per $1,000 principal amount of 2026 Notes (equal to a “base conversion price” of approximately $65.94 per share) plus |
|
b) |
an additional amount of shares per $1,000 of principal amount of 2026 Notes equal to the incremental share factor 2.6762), multiplied by a fraction, the numerator of which is the applicable stock price less the “base conversion price” and the denominator of which is the applicable stock price. |
68
NOTE 5—Loss Per Common Share
Net loss applicable to common stock was used as the numerator in computing basic and diluted loss per common share for the years ended December 31, 2014, 2013 and 2012. The following table sets forth information related to the computations of basic and diluted loss per share.
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
|
|
(Amounts in thousands, except per share data) |
|
|||||||||
|
Basic and Diluted loss per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss applicable to common stock |
|
$ |
(382,858 |
) |
|
$ |
(113,790 |
) |
|
$ |
(90,249 |
) |
|
Weighted-average shares of common stock outstanding |
|
|
44,402 |
|
|
|
38,098 |
|
|
|
36,390 |
|
|
Basic and Diluted loss per share (1) (2) (3) |
|
$ |
(8.62 |
) |
|
$ |
(2.99 |
) |
|
$ |
(2.48 |
) |
|
(1) Common shares issuable upon assumed conversion of convertible preferred stock were not presented as they would have been anti-dilutive. |
|
|
3,588 |
|
|
|
3,588 |
|
|
|
3,588 |
|
|
(2) Common shares issuable upon assumed conversion of the 2026 Notes, the 2029 Notes and 2032 Notes were not presented as they would have been anti-dilutive. |
|
|
4,997 |
|
|
|
6,307 |
|
|
|
6,311 |
|
|
(3) Common shares issuable on assumed conversion of restricted stock and employee stock option were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive. |
|
|
574 |
|
|
|
620 |
|
|
|
238 |
|
NOTE 6—Income Taxes
We did not recognize any current or deferred income tax benefits or expense in 2014, 2013 or 2012.
The following is a reconciliation of the U.S. statutory income tax rate at 35% to our loss before income taxes (in thousands):
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
Income tax (expense) benefit |
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax at U.S. statutory income tax |
|
$ |
123,597 |
|
|
$ |
33,315 |
|
|
$ |
29,471 |
|
|
Valuation allowance |
|
|
(122,032 |
) |
|
|
(30,967 |
) |
|
|
(29,952 |
) |
|
State income taxes-net of federal benefit |
|
|
2,484 |
|
|
|
(902 |
) |
|
|
1,618 |
|
|
Nondeductible expenses and other |
|
|
(4,049 |
) |
|
|
(1,446 |
) |
|
|
(1,137 |
) |
|
Total tax (expense) benefit |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
69
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below (in thousands):
|
|
|
December 31, |
|
|||||
|
|
|
2014 |
|
|
2013 |
|
||
|
Current deferred tax assets: |
|
|
|
|
|
|
|
|
|
Accrued liabilities |
|
$ |
— |
|
|
$ |
133 |
|
|
Contingent liabilities and other |
|
|
366 |
|
|
|
— |
|
|
Compensation |
|
|
1,307 |
|
|
|
— |
|
|
Less valuation allowance |
|
|
(1,566 |
) |
|
|
(126 |
) |
|
Total current deferred tax assets |
|
|
107 |
|
|
|
7 |
|
|
Current deferred tax liabilities: |
|
|
|
|
|
|
|
|
|
Derivative financial instruments |
|
|
(16,569 |
) |
|
|
(646 |
) |
|
Accrued liabilities |
|
|
(26 |
) |
|
|
(26 |
) |
|
Total current deferred tax liabilities |
|
|
(16,595 |
) |
|
|
(672 |
) |
|
Net current deferred tax liability |
|
$ |
(16,488 |
) |
|
$ |
(665 |
) |
|
Noncurrent deferred tax assets: |
|
|
|
|
|
|
|
|
|
Operating loss carry-forwards |
|
$ |
256,240 |
|
|
$ |
211,589 |
|
|
State Tax NOL and Credits |
|
|
7,974 |
|
|
|
5,805 |
|
|
Statutory depletion carry-forward |
|
|
7,035 |
|
|
|
7,035 |
|
|
AMT tax credit carry-forward |
|
|
1,114 |
|
|
|
1,227 |
|
|
Compensation |
|
|
3,105 |
|
|
|
3,496 |
|
|
Contingent liabilities and other |
|
|
46 |
|
|
|
858 |
|
|
Derivative financial instruments |
|
|
162 |
|
|
|
— |
|
|
Accrued liabilities |
|
|
476 |
|
|
|
— |
|
|
Property and equipment |
|
|
82,990 |
|
|
|
(3,248 |
) |
|
Total gross noncurrent deferred tax assets |
|
|
359,142 |
|
|
|
226,762 |
|
|
Less valuation allowance |
|
|
(336,841 |
) |
|
|
(217,558 |
) |
|
Net noncurrent deferred tax assets |
|
|
22,301 |
|
|
|
9,204 |
|
|
Noncurrent deferred tax liabilities: |
|
|
|
|
|
|
|
|
|
Bond discount |
|
|
(89 |
) |
|
|
(74 |
) |
|
Debt discount |
|
|
(5,724 |
) |
|
|
(8,465 |
) |
|
Total non-current deferred tax liabilities |
|
|
(5,813 |
) |
|
|
(8,539 |
) |
|
Net non-current deferred tax asset |
|
$ |
16,488 |
|
|
$ |
665 |
|
The valuation allowance for deferred tax assets increased by $120.7 million in 2014. In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As we have incurred net operating losses in 2014 and prior years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. Therefore, with the before-mentioned adjustment of $120.7 million, we have reduced the carrying value of our net deferred tax asset to zero. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and if we generate taxable income in future periods, we will be able to use our NOLs to offset taxes due at that time. We will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.
As of December 31, 2014, we have federal NOL carry-forwards of approximately $738.2 million for tax purposes which begin to expire in 2026. We also have an alternative minimum tax credit carry-forward not subject to expiration of $1.1 million which will not be used until after the available NOLs have been used or expired and when regular tax exceeds the current year alternative minimum tax.
We did not have any unrecognized tax benefits as of December 31, 2014. The amount of unrecognized tax benefits may change in the next twelve months; however we do not expect the change to have a significant impact on our results of operations or our financial position. We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions. With limited exceptions, we are no longer subject to U.S. Federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2007.
70
Our continuing practice is to recognize estimated interest and penalties related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in the Consolidated Statement of Operations. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations before December 31, 2015.
NOTE 7—Stockholders’ Equity
5.375% Series B Convertible Preferred Stock
During 2005 and 2006 we issued a total of 2,250,000 shares of our 5.375% Series B Convertible Preferred Stock (the “Series B Preferred Stock”) for aggregate net proceeds of $108.8 million (after offering costs of $2.7 million). Each share of the Series B Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears beginning March 15, 2006. If we fail to pay dividends on our Series B Preferred Stock on any six dividend payment dates, whether or not consecutive, the dividend rate per annum will be increased by 1.0% until we have paid all dividends on our Series B Preferred Stock for all dividend periods up to and including the dividend payment date on which the accumulated and unpaid dividends are paid in full.
Each share is convertible at the option of the holder into our common stock at any time at an initial conversion rate of 1.5946 shares of common stock per share, which is equivalent to an initial conversion price of approximately $31.36 per share of common stock. Upon conversion of the Series B Preferred Stock, we may choose to deliver the conversion value to holders in cash, shares of common stock, or a combination of cash and shares of common stock.
If a fundamental change occurs, holders may require us in specified circumstances to repurchase all or part of the Series B Convertible Preferred Stock. In addition, upon the occurrence of a fundamental change or specified corporate events, we will under certain circumstances increase the conversion rate by a number of additional shares of common stock. A “fundamental change” will be deemed to have occurred if any of the following occurs:
|
· |
We consolidate or merge with or into any person or convey, transfer, sell or otherwise dispose of or lease all or substantially all of our assets to any person, or any person consolidates with or merges into us or with us, in any such event pursuant to a transaction in which our outstanding voting shares are changed into or exchanged for cash, securities, or other property; or |
|
· |
We are liquidated or dissolved or adopt a plan of liquidation or dissolution. |
A “fundamental change” will not be deemed to have occurred if at least 90% of the consideration in the case of a merger or consolidation under the first clause above consists of common stock traded on a U.S. national securities exchange and the Series B Preferred Stock becomes convertible solely into such common stock.
As of December 21, 2010, we have the option to cause the Series B Preferred Stock to be automatically converted into the number of shares of common stock that are issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may exercise our conversion right only if, for 20 trading days within any period of 30 consecutive trading days ending on the trading day before the announcement of our exercise of the option, the closing price of the common stock equals or exceeds 130% of the then-prevailing conversion price of the Series B Preferred Stock. The Series B Preferred Stock is non-redeemable by us. There have been no redemptions or conversions in any periods.
10% Series C Cumulative Preferred Stock
In April 2013, we issued $110 million of 10% Series C Cumulative Preferred Stock (the “Series C Preferred Stock”) and received $105.4 million net proceeds from the sale. The sale consisted of 4,400,000 depositary shares each representing a 1/1000th ownership interest in a share of Series C Preferred Stock, par value $1.00 per preferred share with a liquidation preference of $25,000 per preferred share ($25.00 per depositary share) in an underwritten public offering.
The Series C Preferred Stock ranks senior to our common stock and on parity with our 5.375% Series B Cumulative Convertible Preferred Stock and our 9.75% Series D Cumulative Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series C Preferred Stock has no stated maturity and is not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common stock in connection with certain changes of control.
At any time on or after April 10, 2018, we may, at our option, redeem the Series C Preferred Stock, in whole at any time or in part from time to time, for cash at a redemption price of $25,000 per preferred share, plus all accumulated and unpaid dividends to, but
71
not including, the date of redemption. We may redeem the Series C Preferred Stock following certain changes of control, if we do not exercise this option, then the holders of the Series C Preferred Stock have the option to convert the shares of preferred stock into a maximum of 3,371.54 shares of our common stock per share of Series C Preferred Stock, subject to certain adjustments. If we exercise any of our redemption rights relating to shares of Series C Preferred Stock, the holders of Series C Preferred Stock will not have the conversion right described above with respect to the shares of Series C Preferred Stock called for redemption.
Holders of the Series C Preferred Stock have no voting rights except for limited voting rights if we fail to pay dividends for six or more quarterly periods (whether or not consecutive) and in certain other limited circumstances or as required by law.
9.75% Series D Cumulative Preferred Stock
In August 2013, we issued $130 million of 9.75% Series D Cumulative Preferred Stock (the “Series D Preferred Stock”) and received $124.9 million net proceeds from the sale. The sale consisted of 5,200,000 depositary shares each representing a 1/1000th ownership interest in a share of Series D Preferred Stock, par value $1.00 per preferred share with a liquidation preference of $25,000 per preferred share ($25.00 per depositary share) in an underwritten public offering.
The Series D Preferred Stock ranks senior to our common stock and on parity with our Series B Preferred Stock and our Series C Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series D Preferred Stock has no stated maturity and is not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common stock in connection with certain changes of control.
At any time on or after August 19, 2018, we may, at our option, redeem the Series D Preferred Stock, in whole at any time or in part from time to time, for cash at a redemption price of $25,000 per preferred share, plus all accumulated and unpaid dividends to, but not including, the date of redemption. We may redeem the Series D Preferred Stock following certain changes of control, if we do not exercise this option, then the holders of the Series D Preferred Stock have the option to convert the shares of preferred stock into a maximum of 2,297.79 shares of our common stock per share of Series D Preferred Stock, subject to certain adjustments. If we exercise any of our redemption rights relating to shares of Series D Preferred Stock, the holders of Series D Preferred Stock will not have the conversion right described above with respect to the shares of Series D Preferred Stock called for redemption.
Holders of the Series D Preferred Stock have no voting rights except for limited voting rights if we fail to pay dividends for six or more quarterly periods (whether or not consecutive) and in certain other limited circumstances or as required by law.
Common Stock Offering
On October 21, 2013, we closed an underwritten public offering of 6.9 million shares of our common stock sold at a price to the public of $25.25 per share.
NOTE 8—Derivative Activities
We use commodity and financial derivative contracts to manage fluctuations in commodity prices and interest rates. We are currently not designating our derivative contracts for hedge accounting. All derivative gains and losses during 2014, 2013 and 2012 are from our oil and natural gas derivative contracts and have been recognized in “Other income (expense)” on our Consolidated Statements of Operations. Our last interest rate derivative contract ended in 2010.
The following table summarizes the gains and losses we recognized on our oil and natural gas derivatives for the years ended December 31, 2014, 2013 and 2012.
|
|
|
December 31, |
|
|||||||||
|
Oil and Natural Gas Derivatives (in thousands) |
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
Gain (loss) on derivatives not designated as hedges |
|
$ |
49,423 |
|
|
$ |
(702 |
) |
|
$ |
31,882 |
|
72
Commodity Derivative Activity
We enter into swap contracts, costless collars or other derivative agreements from time to time to manage commodity price risk for a portion of our production. Our policy is that all derivative contracts are approved by the Hedging Committee of our Board of Directors, and reviewed periodically by the Board of Directors. As of December 31, 2014, the commodity derivatives we used were in the form of:
|
(a) |
swaps, where we receive a fixed price and pay a floating price, based Argus LLS, and |
|
(b) |
calls, where we grant the counter party the option to buy an underlying commodity at a specified strike price, within a certain period. |
Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Domestic crude oil and natural gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis. We routinely exercise our contractual right to net realized gains against realized losses when settling with our financial counterparties. Neither our counterparties nor we require any collateral upon entering derivative contracts. We would have been at risk of losing a fair value amount of $47.4 million had our counterparties as a group been unable to fulfill their obligations as of December 31, 2014.
As of December 31, 2014, our open positions on our outstanding commodity derivative contracts, all of which were with Royal Bank of Canada, Bank of Montreal, JPMorgan Chase Bank, N.A., Merrill Lynch Commodities, Inc. and Wells Fargo Bank, N.A., were as follows:
|
Contract Type |
|
Daily Volume |
|
|
Total Volume |
|
|
Fixed Price |
|
Fair Value at December 31, 2014 (in thousands) |
|
|||
|
Natural gas calls (MMBtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
20,000 |
|
|
|
7,300,000 |
|
|
$ 5.05-5.06 |
|
$ |
(102 |
) |
|
2016 |
|
|
20,000 |
|
|
|
7,320,000 |
|
|
$ 5.05-5.06 |
|
|
(464 |
) |
|
Oil swaps (BBL) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
3,500 |
|
|
|
1,277,500 |
|
|
$ 94.55-98.10 |
|
|
47,444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
46,878 |
|
The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each level as of December 31, 2014 and 2013 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Footnote 1 “Fair Value Measurement” for our discussion for inputs used and valuation techniques for determining fair values.
|
|
|
2014 Fair Value Measurements Using |
|
|||||||||||||
|
Description |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
||||
|
Current Assets Commodity Derivatives |
|
$ |
— |
|
|
$ |
47,444 |
|
|
$ |
— |
|
|
$ |
47,444 |
|
|
Non-current Assets Commodity Derivatives |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Current Liabilities Commodity Derivatives |
|
|
— |
|
|
|
(102 |
) |
|
|
— |
|
|
|
(102 |
) |
|
Non-current Liabilities Commodity Derivatives |
|
|
— |
|
|
|
(464 |
) |
|
|
— |
|
|
|
(464 |
) |
|
Total |
|
$ |
— |
|
|
$ |
46,878 |
|
|
$ |
— |
|
|
$ |
46,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 Fair Value Measurements Using |
|
|||||||||||||
|
Description |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
||||
|
Current Assets Commodity Derivatives |
|
$ |
— |
|
|
$ |
6,187 |
|
|
$ |
— |
|
|
$ |
6,187 |
|
|
Non-current Assets Commodity Derivatives |
|
|
— |
|
|
|
1,396 |
|
|
|
— |
|
|
|
1,396 |
|
|
Current Liabilities Commodity Derivatives |
|
|
— |
|
|
|
(4,341 |
) |
|
|
— |
|
|
|
(4,341 |
) |
|
Non-current Liabilities Commodity Derivatives |
|
|
— |
|
|
|
(2,371 |
) |
|
|
— |
|
|
|
(2,371 |
) |
|
Total |
|
$ |
— |
|
|
$ |
871 |
|
|
$ |
— |
|
|
$ |
871 |
|
73
We enter into oil and natural gas derivative contracts under which we have netting arrangements with each counter party. The following table discloses and reconciles the gross amounts to the amounts as presented on the Statements of Financial Position for the periods ending December 31, 2014 and December 31, 2013.
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
||||||||||||||||||
|
Fair Value of Oil and Natural Gas Derivatives (in thousands) |
|
Gross Amount |
|
|
Amount Offset |
|
|
As Presented |
|
|
Gross Amount |
|
|
Amount Offset |
|
|
As Presented |
|
||||||
|
Derivative Current Asset |
|
$ |
47,444 |
|
|
$ |
— |
|
|
$ |
47,444 |
|
|
$ |
6,658 |
|
|
$ |
(471 |
) |
|
$ |
6,187 |
|
|
Derivative Non-current Asset |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,396 |
|
|
|
— |
|
|
|
1,396 |
|
|
Derivative Current Liability |
|
|
(102 |
) |
|
|
— |
|
|
|
(102 |
) |
|
|
(4,812 |
) |
|
|
471 |
|
|
|
(4,341 |
) |
|
Derivative Non-current Liability |
|
|
(464 |
) |
|
|
— |
|
|
|
(464 |
) |
|
|
(2,371 |
) |
|
|
— |
|
|
|
(2,371 |
) |
|
Total |
|
$ |
46,878 |
|
|
$ |
— |
|
|
$ |
46,878 |
|
|
$ |
871 |
|
|
$ |
— |
|
|
$ |
871 |
|
NOTE 9—Commitments and Contingencies
We are party to various lawsuits from time to time arising in the normal course of business, including, but not limited to, royalty, contract, personal injury, and environmental claims. We have established reserves as appropriate for all such proceedings and intend to vigorously defend these actions. Management believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our consolidated financial position results of operations or liquidity.
The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2014 (in thousands).
|
|
|
Payment due by Period |
|
|||||||||||||||||||||||||
|
|
|
Note |
|
|
Total |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 and After |
|
|||||||
|
Debt (1) |
|
|
4 |
|
|
$ |
462,496 |
|
|
$ |
— |
|
|
$ |
429 |
|
|
$ |
180,375 |
|
|
$ |
— |
|
|
$ |
281,692 |
|
|
Interest on notes |
|
|
4 |
|
|
|
127,185 |
|
|
|
33,067 |
|
|
|
33,066 |
|
|
|
30,975 |
|
|
|
24,741 |
|
|
|
5,336 |
|
|
Office space leases |
|
|
|
|
|
|
4,914 |
|
|
|
983 |
|
|
|
1,020 |
|
|
|
1,057 |
|
|
|
1,093 |
|
|
|
761 |
|
|
Office equipment leases |
|
|
|
|
|
|
311 |
|
|
|
231 |
|
|
|
62 |
|
|
|
18 |
|
|
|
— |
|
|
|
— |
|
|
Drilling rigs & operations contracts |
|
|
|
|
|
|
7,065 |
|
|
|
6,946 |
|
|
|
97 |
|
|
|
22 |
|
|
|
— |
|
|
|
— |
|
|
Transportation contracts |
|
|
|
|
|
|
5,391 |
|
|
|
1,264 |
|
|
|
1,032 |
|
|
|
1,032 |
|
|
|
1,032 |
|
|
|
1,031 |
|
|
Total contractual obligations (2) |
|
|
|
|
|
$ |
607,362 |
|
|
$ |
42,491 |
|
|
$ |
35,706 |
|
|
$ |
213,479 |
|
|
$ |
26,866 |
|
|
$ |
288,820 |
|
|
(1) |
The 2026 Notes have a provision at the end of years five, ten and 15, for the investors to demand payment on these dates; the first such date was December 1, 2011; all but the remaining $0.4 million were redeemed. The next ‘put’ date for the remaining 2026 Notes is December 1, 2016. The 2029 Notes have a provision by which on or after October 1, 2014, we may redeem all or a portion of the notes for cash and the investors may require us to repurchase the notes on each of October 1, 2014, 2019 and 2024; all but the remaining $6.7 million were redeemed in 2014. The 2032 Notes have a provision by which on or after October 1, 2017, we may redeem all or a portion of the notes for cash, and the investors may require us to repurchase the notes on each of October 1, 2017, 2022 and 2027. The balance outstanding under our Senior Credit Facility is not included as it is revolving debt. |
|
(2) |
This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $6.5 million as of December 31, 2014. We record a separate liability for the asset retirement obligations. See Note 3. |
Operating Leases—We have commitments under an operating lease agreements for office space and office equipment leases. Total rent expense for the years ended December 31, 2014, 2013 and 2012, was approximately $1.4 million, $1.3 million and $1.2 million, respectively.
Drilling Contracts—We have two drilling rigs under contract as of December 31, 2014 which are scheduled to expire in 2015.
Defined Contribution Plan – We have a defined contribution plan (“DCP”) which matches a portion of employees’ contributions. Participation in the DCP is voluntary and all regular employees of the Company are eligible to participate. We charged to expense plan contributions of $0.6 million $0.7 million and $0.7 million for 2014, 2013 and 2012, respectively.
Transportation Contracts - We have commitments under a transportation contract for our Eagle Ford Shale Trend properties. See Note 1 “-Transportation Obligation” for further information.
74
NOTE 10—Related Party Transactions
Patrick E. Malloy, III, Chairman of the Board of Directors of our company is a principal of Malloy Energy Company, LLC (“MEC”). MEC owns various small working interests in the Bethany Longstreet field for which we are the operator. In accordance with industry standard joint operating agreements, we bill MEC for its share of capital and operating cost on a monthly basis. As of December 31, 2014 and 2013, the amounts billed and outstanding to MEC for its share of monthly capital and operating costs were both less than $0.1 million and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by MEC to us in the month after billing and is current on payment of its billings. Billings for the years ended December 31, 2014 and 2013 were $0.4 million in both periods. Revenue distributions for the same periods totaled $0.5 million and $0.8 million, respectively.
We also serve as the operator for a number of other oil and natural gas wells owned by affiliates of MEC in which we will earn a working interest after payout. In accordance with industry standard joint operating agreements, we bill the affiliates for its share of the capital and operating costs of these wells on a monthly basis. As of December 31, 2014 and 2013, the amounts billed and outstanding to the affiliate for its share of monthly capital and operating costs were both less than $0.3 million and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by the affiliate to us in the month after billing and the affiliate is current on payment of its billings. Billings to these affiliates totaled $1.2 million and $0.8 million for the years ended December 31, 2014 and 2013, respectively. Revenue distributions during the same periods totaled $1.2 million and $1.4 million, respectively.
Note 11 – Dispositions and Acquisitions
On December 22, 2014 we closed on the sale of our interest in the Beckville, North Minden and West Brachfield fields located in Panola and Rusk Counties, Texas for $61.0 million. We received net proceeds of $53.3 million after closing adjustments based upon an effective date of July 1, 2014. We used the net proceeds from the sale to repay borrowings under our Senior Credit Facility. We recorded a loss on sale of assets of $3.5 million.
On August 21, 2013, we closed on an acquisition of a 66.7% working interest in producing assets and mineral lease acreage in the TMS from Devon Energy Production Company, L.P. ("Devon") with an effective date of March 1, 2013. The closing price after purchase price adjustments was $24.6 million. The closing price included $2.7 million of lease extensions executed by Devon for the Company after the effective date. The adjusted purchase price net of lease extension costs totaled $21.8 million.
Note 12 – Subsequent Events
On February 26, 2015 we entered into a definitive purchase agreement to issue an aggregate principal amount of $ 100 million of second lien senior secured notes. The debt financing, which is for a term of three years, carries an 8.0% coupon which is payable semi-annually. Additionally, the purchaser of the notes will receive 4.9 million common stock warrants exercisable at a 10% premium to our common stock closing price on the date the agreement is executed. The proceeds will be used to pay down the amount we have drawn on our Senior Credit Facility.
75
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY
SUPPLEMENTAL INFORMATION
(Unaudited)
Oil and Natural Gas Producing Activities (Unaudited)
Overview
All of our reserve information related to crude oil, condensate and natural gas liquids and natural gas was compiled based on estimates prepared and reviewed by our engineers. The technical persons primarily responsible for overseeing the preparation of the reserves estimates meet the requirements regarding qualifications. The reserves estimation is part of our internal controls process subject to management’s annual review and approval. These reserves estimates are prepared by Netherland, Sewell & Associates, Inc. (“NSAI”) and Ryder Scott Company (“RSC”), our independent reserve engineer consulting firms, as of December 31, 2014 and 2013. NSAI prepared the reserves estimates as of December 31, 2012. Approximately 35% and 65% of the proved reserves estimates shown herein at December 31, 2014 have been independently prepared by NSAI and RSC, respectively. NSAI prepared the estimates on all our proved reserves as of December 31, 2014 on our properties other than in the TMS and the Eagle Ford Shale Trend areas. RSC prepared the estimate of proved reserves as of December 31, 2014 for our TMS and Eagle Ford Trend areas. Copies of the summary reserve reports of NSAI and RSC for 2014 are filed as exhibits 99.1 and 99.2, respectively to this Annual Report on Form 10-K. All of the subject reserves are located in the continental United States, primarily in Texas, Louisiana and Mississippi.
Many assumptions and judgmental decisions are required to estimate reserves. Quantities reported are considered reasonable but are subject to future revisions, some of which may be substantial, as additional information becomes available. Such additional knowledge may be gained as the result of reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, and other factors.
Regulations published by the SEC define proved oil and natural gas reserves as those quantities of oil and natural gas which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well.
Prices we used to value our reserves are based on the twelve-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2014. For oil volumes, the average price of $94.99 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For natural gas volumes, the average price of $4.35 per MMBtu is adjusted by lease for energy content, transportation fees, and regional price differentials. For natural gas liquids, the average price was $44.84 per Bbl.
Capitalized Costs
The table below reflects our capitalized costs related to our oil and natural gas producing activities at December 31, 2014 and 2013 (in thousands):
|
|
|
2014 |
|
|
2013 |
|
||
|
Proved properties |
|
$ |
1,356,786 |
|
|
$ |
1,728,353 |
|
|
Unproved properties |
|
|
121,256 |
|
|
|
109,867 |
|
|
|
|
|
1,478,042 |
|
|
|
1,838,220 |
|
|
Less: accumulated depreciation, depletion and amortization |
|
|
(864,926 |
) |
|
|
(1,016,423 |
) |
|
Net oil and natural gas properties |
|
$ |
613,116 |
|
|
$ |
821,797 |
|
We have $14.5 million of capitalized exploratory well costs that are pending the determination of proved reserves as of December 31, 2014 and had $9.7 million as of December 31, 2013. During 2014, none of the December 31, 2013 pending capitalized exploratory well costs were expensed.
76
Costs Incurred
Costs incurred in oil and natural gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows (in thousands):
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
Property Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
$ |
23,197 |
|
|
$ |
22,973 |
|
|
$ |
22,325 |
|
|
Proved |
|
|
— |
|
|
|
15,533 |
|
|
|
— |
|
|
Exploration |
|
|
75,384 |
|
|
|
85,425 |
|
|
|
34,529 |
|
|
Development (1) |
|
|
237,087 |
|
|
|
136,242 |
|
|
|
198,918 |
|
|
|
|
$ |
335,668 |
|
|
$ |
260,173 |
|
|
$ |
255,772 |
|
|
(1) |
Includes asset retirement costs of $0.4 million in 2014, $1.8 million in 2013 and $2.7 million in 2012. |
The following table sets forth our net proved oil and natural gas reserves at December 31, 2014, 2013 and 2012 and the changes in net proved oil and natural gas reserves during such years, as well as proved developed and proved undeveloped reserves at the beginning and end of each year:
|
|
|
Natural Gas (Mmcf) |
|
|
Oil, Condensate and NGLs (MBbls) |
|
||||||||||||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
||||||
|
Net proved reserves at beginning of period |
|
|
329,616 |
|
|
|
253,981 |
|
|
|
408,707 |
|
|
|
20,431 |
|
|
|
13,189 |
|
|
|
13,516 |
|
|
Revisions of previous estimates (1) |
|
|
(108,029 |
) |
|
|
78,965 |
|
|
|
(112,601 |
) |
|
|
(1,378 |
) |
|
|
1,992 |
|
|
|
(1,372 |
) |
|
Extensions, discoveries and improved recovery (2) |
|
|
1,655 |
|
|
|
17,776 |
|
|
|
4,420 |
|
|
|
16,452 |
|
|
|
6,165 |
|
|
|
4,661 |
|
|
Purchases of minerals in place |
|
|
— |
|
|
|
49 |
|
|
|
— |
|
|
|
— |
|
|
|
476 |
|
|
|
— |
|
|
Sales of minerals in place |
|
|
(101,810 |
) |
|
|
(148 |
) |
|
|
(20,919 |
) |
|
|
(5,669 |
) |
|
|
— |
|
|
|
(2,524 |
) |
|
Production |
|
|
(16,600 |
) |
|
|
(21,007 |
) |
|
|
(25,626 |
) |
|
|
(1,693 |
) |
|
|
(1,391 |
) |
|
|
(1,092 |
) |
|
Net proved reserves at end of period |
|
|
104,832 |
|
|
|
329,616 |
|
|
|
253,981 |
|
|
|
28,143 |
|
|
|
20,431 |
|
|
|
13,189 |
|
|
Net proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
117,184 |
|
|
|
119,671 |
|
|
|
169,344 |
|
|
|
10,100 |
|
|
|
6,447 |
|
|
|
6,532 |
|
|
End of period |
|
|
60,708 |
|
|
|
117,184 |
|
|
|
119,671 |
|
|
|
10,719 |
|
|
|
10,100 |
|
|
|
6,447 |
|
|
Net proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
212,432 |
|
|
|
134,310 |
|
|
|
239,364 |
|
|
|
10,331 |
|
|
|
6,742 |
|
|
|
6,984 |
|
|
End of period |
|
|
44,124 |
|
|
|
212,432 |
|
|
|
134,310 |
|
|
|
17,424 |
|
|
|
10,331 |
|
|
|
6,742 |
|
77
|
|
|
Natural Gas Equivalents (Mmcfe) |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
Net proved reserves at beginning of period |
|
|
452,203 |
|
|
|
333,116 |
|
|
|
489,805 |
|
|
Revisions of previous estimates (1) |
|
|
(116,298 |
) |
|
|
90,919 |
|
|
|
(120,832 |
) |
|
Extensions, discoveries and improved recovery (2) |
|
|
100,367 |
|
|
|
54,765 |
|
|
|
32,387 |
|
|
Purchases of minerals in place |
|
|
— |
|
|
|
2,903 |
|
|
|
— |
|
|
Sales of minerals in place (3) |
|
|
(135,825 |
) |
|
|
(148 |
) |
|
|
(36,063 |
) |
|
Production |
|
|
(26,758 |
) |
|
|
(29,352 |
) |
|
|
(32,181 |
) |
|
Net proved reserves at end of period |
|
|
273,689 |
|
|
|
452,203 |
|
|
|
333,116 |
|
|
Net proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
177,786 |
|
|
|
158,352 |
|
|
|
208,538 |
|
|
End of period |
|
|
125,019 |
|
|
|
177,786 |
|
|
|
158,352 |
|
|
Net proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
274,417 |
|
|
|
174,764 |
|
|
|
281,267 |
|
|
End of period |
|
|
148,670 |
|
|
|
274,417 |
|
|
|
174,764 |
|
|
(1) |
Revisions of previous estimates in 2014 were negative, primarily due to the transfer of undeveloped volumes out of the proved category. |
|
(2) |
Extensions and discoveries were positive on an overall basis in all three periods presented, primarily related to our continued drilling activity on existing properties in Southwest Mississippi, Southeast Louisiana and South Texas areas. We recognized reserve adds of 100.4 Bcfe in 2014 related to extensions and discoveries, of which approximately 91.6 Bcfe is attributed to the Tuscaloosa Marine Shale Trend and 8.8 Bcfe is attributed to the Eagle Ford Shale Trend. |
|
(3) |
In 2014, we sold approximately 135.8 Bcfe attributed to the sale of properties in the Beckville, Brachfield, Carthage and North Minden fields located in East Texas.. |
Standardized Measure
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of year-end is shown below (in thousands):
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
Future revenues |
|
$ |
2,984,283 |
|
|
$ |
2,568,448 |
|
|
$ |
1,608,629 |
|
|
Future lease operating expenses and production taxes |
|
|
(998,874 |
) |
|
|
(787,619 |
) |
|
|
(467,600 |
) |
|
Future development costs (1) |
|
|
(656,659 |
) |
|
|
(713,121 |
) |
|
|
(465,500 |
) |
|
Future income tax expense |
|
|
(14,531 |
) |
|
|
(11,153 |
) |
|
|
(4,149 |
) |
|
Future net cash flows |
|
|
1,314,219 |
|
|
|
1,056,555 |
|
|
|
671,380 |
|
|
10% annual discount for estimated timing of cash flows |
|
|
(669,483 |
) |
|
|
(588,408 |
) |
|
|
(313,931 |
) |
|
Standardized measure of discounted future net cash flows |
|
$ |
644,736 |
|
|
$ |
468,147 |
|
|
$ |
357,449 |
|
|
Index price used to calculate reserves (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
|
$ |
4.35 |
|
|
$ |
3.67 |
|
|
$ |
2.76 |
|
|
Oil (per Bbl) |
|
$ |
94.99 |
|
|
$ |
96.94 |
|
|
$ |
91.21 |
|
|
(1) |
Includes cumulative asset retirement obligations of $17.9 million, $42.8 million and $34.9 million in 2014, 2013 and 2012, respectively. |
|
(2) |
These index prices, used to estimate our reserves at these dates, are before deducting or adding applicable transportation and quality differentials on a well-by-well basis. |
78
Changes in the Standardized Measure
The following are the principal sources of change in the standardized measure of discounted net cash flows for the years shown (in thousands):
|
|
|
Year Ended December 31, |
|
|||||||||
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
Balance, beginning of year |
|
$ |
468,147 |
|
|
$ |
357,449 |
|
|
$ |
447,970 |
|
|
Net changes in prices and production costs related to future production |
|
|
68,605 |
|
|
|
(5,614 |
) |
|
|
(193,096 |
) |
|
Sales and transfers of oil and natural gas produced, net of production costs |
|
|
(169,114 |
) |
|
|
(165,452 |
) |
|
|
(146,490 |
) |
|
Net change due to revisions in quantity estimates |
|
|
(256,200 |
) |
|
|
156,009 |
|
|
|
(178,468 |
) |
|
Net change due to extensions, discoveries and improved recovery |
|
|
377,823 |
|
|
|
145,843 |
|
|
|
197,583 |
|
|
Net change due to purchases and sales of minerals in place |
|
|
(2,511 |
) |
|
|
16,371 |
|
|
|
(74,633 |
) |
|
Changes in future development costs |
|
|
153,532 |
|
|
|
(103,033 |
) |
|
|
208,619 |
|
|
Previously estimated development cost incurred in period |
|
|
17,191 |
|
|
|
50,402 |
|
|
|
69,688 |
|
|
Net change in income taxes |
|
|
(1,727 |
) |
|
|
(2,476 |
) |
|
|
2,394 |
|
|
Accretion of discount |
|
|
47,227 |
|
|
|
35,909 |
|
|
|
45,201 |
|
|
Change in production rates (timing) and other |
|
|
(58,237 |
) |
|
|
(17,261 |
) |
|
|
(21,319 |
) |
|
Net increase (decrease) in standardized measures |
|
|
176,589 |
|
|
|
110,698 |
|
|
|
(90,521 |
) |
|
Balance, end of year |
|
$ |
644,736 |
|
|
$ |
468,147 |
|
|
$ |
357,449 |
|
We believe with reasonable certainty that we will be able to obtain such capital in the normal course of business. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted cash flows is the future net cash flows less the computed discount.
Summarized Quarterly Financial Data (Unaudited)
(In Thousands, Except Per Share Amounts)
|
|
|
First Quarter |
|
|
Second Quarter |
|
|
Third Quarter |
|
|
Fourth Quarter |
|
|
Total |
|
|||||
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
51,803 |
|
|
$ |
53,319 |
|
|
$ |
54,874 |
|
|
$ |
48,557 |
|
|
$ |
208,553 |
|
|
Operating income (loss) |
|
|
(2,123 |
) |
|
|
(3,552 |
) |
|
|
(87,420 |
) |
|
|
(261,725 |
) |
|
|
(354,820 |
) |
|
Net income (loss) |
|
|
(22,492 |
) |
|
|
(25,106 |
) |
|
|
(79,711 |
) |
|
|
(225,827 |
) |
|
|
(353,136 |
) |
|
Net income (loss) applicable to common stock |
|
|
(29,923 |
) |
|
|
(32,536 |
) |
|
|
(87,142 |
) |
|
|
(233,257 |
) |
|
|
(382,858 |
) |
|
Basic income (loss) per common share |
|
|
(0.68 |
) |
|
|
(0.73 |
) |
|
|
(1.96 |
) |
|
|
(5.23 |
) |
|
|
(8.62 |
) |
|
Diluted income (loss) per common share |
|
|
(0.68 |
) |
|
|
(0.73 |
) |
|
|
(1.96 |
) |
|
|
(5.23 |
) |
|
|
(8.62 |
) |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
47,084 |
|
|
$ |
48,485 |
|
|
$ |
57,161 |
|
|
$ |
50,565 |
|
|
$ |
203,295 |
|
|
Operating income (loss) |
|
|
(13,142 |
) |
|
|
(14,192 |
) |
|
|
(854 |
) |
|
|
(8,122 |
) |
|
|
(36,310 |
) |
|
Net income (loss) |
|
|
(28,463 |
) |
|
|
(16,143 |
) |
|
|
(27,085 |
) |
|
|
(23,495 |
) |
|
|
(95,186 |
) |
|
Net income (loss) applicable to common stock |
|
|
(29,975 |
) |
|
|
(20,099 |
) |
|
|
(32,790 |
) |
|
|
(30,926 |
) |
|
|
(113,790 |
) |
|
Basic income (loss) per common share |
|
|
(0.82 |
) |
|
|
(0.55 |
) |
|
|
(0.89 |
) |
|
|
(0.73 |
) |
|
|
(2.99 |
) |
|
Diluted income (loss) per common share |
|
|
(0.82 |
) |
|
|
(0.55 |
) |
|
|
(0.89 |
) |
|
|
(0.73 |
) |
|
|
(2.99 |
) |
None.
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission and that any material information relating to us is recorded, processed, summarized and reported to our management including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable
79
assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
As required by SEC rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(c) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of December 31, 2014, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective.
Management’s Annual Report on Internal Control Over Financial Reporting
See “Management’s Assessment of Internal Control Over Financial Reporting” (under Item 8 of this Annual Report on Form 10-K).
Attestation Report of the Registered Public Accounting Firm
See “Report of Independent Registered Public Accounting Firm” (under Item 8 of this Annual Report on Form 10-K).
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.
On February 26, 2015, the Company entered into a purchase agreement the (“Purchase Agreement”) by and among the Company and Franklin Advisers, Inc., as investment manager on behalf of certain funds and accounts (the “Purchaser”). Under the terms of the Purchase Agreement, the Company agreed to issue and sell to the Purchaser 100,000 Units (the “Units”), each consisting of $1,000 aggregate principal amount at maturity of its 8.00% Senior Secured Second Lien Notes due 2018 (the “Notes”) and one warrant (the “Warrants”) to purchase 48.84 shares of the Company’s common stock.
The Notes will be issued pursuant to an indenture between the Company, Goodrich Petroleum Company, L.L.C. (the “Guarantor”) and U.S. Bank National Association, as Trustee, substantially in the form attached to the Purchase Agreement (the “Indenture”), and will be guaranteed on a senior secured, second-priority basis by the Guarantor (the “Guarantee” and, together with the Notes and the Warrants, the “Securities”). The Notes and the Guarantee are secured on a senior second-priority basis by liens on certain of the assets of the Company and Guarantor.
The Warrants will be issued pursuant to a warrant agreement between the Company and American Stock Transfer & Trust Company LLC, substantially in the form attached to the Purchase Agreement (the “Warrant Agreement”). Under the terms of the Warrant Agreement, the Notes and the Warrants will not be separately transferable until the earliest of (i) 365 days after the date on which the Warrants are originally issued, (ii) the date on which a registration statement related to the resale of the warrants is declared effective, (iii) the date on which a registration statement with respect to a registered exchange offer for the Notes is declared effective and (iv) in the event of the occurrence of a change of control (as defined in the Indenture),the date on which requisite notice of such change of control is mailed to the holders of Notes. At such time, the Warrants will become exercisable upon payment of the exercise price of $4.664 or convertible on a cashless basis on the basis set forth in the Warrant Agreement. Any Warrants not exercised in ten years will expire.
The issuance and sale of the Units is expected to close on March 12, 2015, subject to customary closing conditions. The issuance and sale of the Units pursuant to the Purchase Agreement is exempt from registration requirements of the Securities Act of 1933, as amended and the Company has agreed not to take any action that would cause the loss of such exemption.
The description of the Indenture, the Warrant Agreement and the Purchase Agreement above does not purport to be complete and are qualified in their entirety by reference to the complete text of the Purchase Agreement and the forms of the Indenture and Warrant Agreement made part of the Purchase Agreement, a copy of which is filed as Exhibit 4.16 to this Annual Report on Form 10-K and which is incorporated herein by reference.
80
PART III
Our executive officers and directors and their ages and positions as of February 27, 2015, are as follows:
|
Name |
|
Age |
|
|
Position |
|
|
Patrick E. Malloy, III |
|
|
72 |
|
|
Chairman of the Board of Directors |
|
Walter G. “Gil” Goodrich |
|
|
56 |
|
|
Vice Chairman, Chief Executive Officer and Director |
|
Robert C. Turnham, Jr. |
|
|
57 |
|
|
President, Chief Operating Officer and Director |
|
Mark E. Ferchau |
|
|
61 |
|
|
Executive Vice President |
|
Jan L. Schott |
|
|
46 |
|
|
Senior Vice President and Chief Financial Officer |
|
Michael J. Killelea |
|
|
52 |
|
|
Senior Vice President, General Counsel and Corporate Secretary |
|
Josiah T. Austin |
|
|
67 |
|
|
Director |
|
Peter D. Goodson |
|
|
72 |
|
|
Director |
|
Michael J. Perdue |
|
|
60 |
|
|
Director |
|
Arthur A. Seeligson |
|
|
56 |
|
|
Director |
|
Stephen M. Straty |
|
|
59 |
|
|
Director |
|
Gene Washington |
|
|
68 |
|
|
Director |
Josiah T. Austin is the managing member of El Coronado Holdings, L.L.C., a privately owned investment holding company. He and his family own and operate agricultural properties in the state of Arizona and northern Sonora, Mexico through El Coronado Ranch & Cattle Company, L.L.C. and other entities. Mr. Austin previously served on the Board of Directors of Monterey Bay Bancorp of Watsonville, California, and is a prior board member of New York Bancorp, Inc., which merged with North Fork Bancorporation in 1998. He is an active investor in publicly traded financial institutions and is currently on The Board of Directors of Novogen, LTD. He became one of our directors in 2002.
Mark E. Ferchau became Executive Vice President of the Company in 2004. He had previously served as the Company’s Senior Vice President, Engineering and Operations, after initially joining the Company as a Vice President in 2001. Mr. Ferchau previously served as Production Manager for Forcenergy Inc. from 1997 to 2001 and as Vice President, Engineering of Convest Energy Corporation from 1993 to 1997. Prior thereto, Mr. Ferchau held various positions with Wagner & Brown, Ltd. and other independent oil and natural gas companies.
Walter G. “Gil” Goodrich became Vice Chairman of our Board in 2003. He has served as our Chief Executive Officer since 1995. Mr. Goodrich was Goodrich Oil Company’s Vice President of Exploration from 1985 to 1989 and its President from 1989 to 1995. He joined Goodrich Oil Company, which held interests in and served as operator of various properties owned by a predecessor of the Company, as an exploration geologist in 1980. Gil Goodrich is the son of Henry Goodrich. He has served as a director since 1995.
Peter D. Goodson has been a lead member of the Mekong Capital Advisory Board, a Vietnamese private equity firm since 2010, an operating partner of Dubilier & Company since 1998 and a visiting lecturer at Haas Business School of the University of California, Berkeley, and the Berkeley-Columbia program where he has lectured since January 2004. Mr. Goodson is a former director of dELiA*s, Inc., Montgomery Ward & Co., Kidder, Peabody & Co., Broadgate Consultants, Silicon Valley Bancshares, the former New York Bancorp, Inc., and Dial Industries. He was elected to the Company’s Board of Directors in 2011.
Michael J. Killelea joined the Company as Senior Vice President, General Counsel and Corporate Secretary in 2009. Mr. Killelea has almost 25 years of experience in the energy industry. In 2008, he served as interim Vice President, General Counsel and Corporate Secretary for Maxus Energy Corporation. Prior to that time, Mr. Killelea was Senior Vice President, General Counsel and Corporate Secretary of Pogo Producing Company from 2000 through 2007.
Patrick E Malloy, III became Chairman of the Board of Directors in 2003. He has been President and Chief Executive Officer of Malloy Enterprises, Inc., a real estate and investment holding company, and Malloy Real Estate, Inc. since 1973. In addition, Mr. Malloy served as a director of North Fork Bancorp (NYSE) from 1998 to 2002 and was Chairman of the Board of New York Bancorp (NYSE) from 1991 to 1998. He joined our Board of Directors in 2000.
Michael J. Perdue is the President of PacWest Bancorp., a publicly traded holding company and of its subsidiary, Pacific Western Bank, both based in San Diego, California. Before assuming his present position in 2006, Mr. Perdue served as President and Chief Executive Officer of Community Bancorp Inc., from 2003. Over the course of his career, Mr. Perdue has held executive positions with several banking and real estate development organizations. He was elected to our Board of Directors in 2001.
81
Arthur A. Seeligson has been Managing Partner of Seeligson Oil Co. Ltd. since 1996 and also manages a family investment office in Houston, Texas. Previously, Mr. Seeligson was an investment banker focused on the oil and gas industry. He has served as one of our directors since 1995.
Jan L. Schott has served as Senior Vice President and Chief Financial Officer since 2010 and currently serves as both the Company’s Principal Financial Officer. She joined the company in 2007 as Vice President and Controller. Ms. Schott has over 20 years of experience with the energy industry. Prior to joining the Company, Ms. Schott served in various accounting management positions with Apache Corporation from 1997 to 2007. Ms. Schott was in public accounting with KPMG LLP from 1991 to 1997. Ms. Schott is a certified public accountant.
Stephen M. Straty is the America’s Co-Head Energy Investment Banking Group at Jefferies & Company, Inc. Mr. Straty joined the firm in 2008 and has nearly 30 years of experience in finance, most recently as Senior Managing Director and Head of the Natural Resources Group at Bear, Stearns & Co., Inc. where he worked for 17 years. Mr. Straty has extensive experience in serving a broad array of energy clients, having completed over $40.0 billion in merger and acquisition and financing assignments during the past ten years. He has served as a director since 2009.
Robert C. Turnham, Jr. has served as our Chief Operating Officer since 1995 and became President and Chief Operating Officer in 2003. He has held various positions in the oil and natural gas business since 1981. From 1981 to 1984, Mr. Turnham served as a financial analyst for Pennzoil. In 1984, he formed Turnham Interests, Inc. to pursue oil and natural gas investment opportunities. From 1993 to 1995, he was a partner in and served as President of Liberty Production Company, an oil and natural gas exploration and production company. He has served as a director since 2006.
Gene Washington is the former Director of Football Operations with the National Football League in New York. He previously served as a professional sportscaster and as Assistant Athletic Director for Stanford University prior to assuming his present position with the NFL in 1994. Mr. Washington serves and has served on numerous corporate and civic boards, including serving as a director of the former New York Bancorp, a NYSE listed company. He was elected to the Company’s Board of Directors in 2003.
Additional information required under Item 10, “Directors, Executive Officers and Corporate Governance,” will be provided in our Proxy Statement for the 2015 Annual Meeting of Stockholders. The information required by this Item is incorporated by reference to the information provided in our definitive proxy statement for the 2015 annual meeting of stockholders to be filed within 120 days from December 31, 2014. Additional information regarding our corporate governance guidelines as well as the complete text of our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and our Nominating and Corporate Governance Committee may be found on our website at www.goodrichpetroleum.com.
The information required by this Item is incorporated by reference to the information provided under the caption “Executive Compensation” in our definitive proxy statement for the 2015 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2014.
|
Item 12. |
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information required by this Item is incorporated by reference to the information provided under the caption “Security Ownership of Certain Beneficial Owners and Management” in our definitive proxy statement for the 2015 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2014.
The information required by this Item is incorporated by reference to the information provided under the caption “Transactions with Related Persons” and “Corporate Governance-Our Board-Board Size; Director Independence” in our definitive proxy statement for the 2015 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2014.
The information required by this Item is incorporated by reference to the information provided under the caption “Audit and Non-Audit Fees” in our definitive proxy statement for the 2015 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2014.
82
PART IV
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See “Index to Consolidated Financial Statements” on page 52.
All schedules are omitted because they are not applicable, not required or the information is included within the consolidated financial information or related notes.
(a)(3) Exhibits
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3.2 |
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Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Acquisition II, Inc., dated January 31, 1997 (Incorporated by reference to Exhibit 3.1 B of the Company’s Third Amended Registration Statement of Form S-1 (Registration No. 333-47078) filed on December 8, 2000).
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3.3 |
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Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated March 12, 1998 (Incorporated by reference to Exhibit 3.2 of the Company’s Annual Report on Form 10-K (File No. 001-12719) for the year ended December 31, 1997).
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3.4 |
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Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 9, 2002 (Incorporated by reference to Exhibit 3.4 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on December 3, 2007).
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3.5 |
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Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 30, 2007 (Incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on August 9, 2007).
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3.6 |
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Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 3.2 of the Company’s Form 8-K (File No. 001-12719) filed on February 19, 2008).
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3.7 |
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Certificate of Designation of 5.375% Series B Cumulative Convertible Preferred Stock (Incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K (File No. 001-12719) filed on December 22, 2005).
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3.8 |
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Certificate of Designation with respect to the 10.00% Series C Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on April 10, 2013).
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3.9 |
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Certificate of Designation with respect to the 9.75% Series D Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on August 19, 2013).
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4.1 |
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Specimen Common Stock Certificate (Incorporated by reference to Exhibit 4.6 of the Company’s Registration Statement on Form S-8 (File No. 33-01077) filed February 20, 1996).
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4.2 |
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Deposit Agreement, dated as of April 10, 2013, by and among Goodrich Petroleum Corporation, American Stock Transfer & Trust Company, as Depositary, and the holders from time to time of the depositary receipts described therein (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on April 10, 2013).
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4.3 |
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Form of Depositary Receipt representing the Depositary Shares (included as Exhibit A to Exhibit 4.1) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on April 10, 2013).
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4.4 |
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Form of Certificate representing the 10.00% Series C Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on April 10, 2013).
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4.5 |
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Deposit Agreement, dated as of August 19, 2013 by and among Goodrich Petroleum Corporation, American Stock Transfer & Trust Company, as Depositary, and the holders from time to time of the depositary receipts described therein (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on August 19, 2013).
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83
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4.6 |
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Form of Depositary Receipt representing the Depositary Shares (included as Exhibit A to Exhibit 4.8) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on August 19, 2013).
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4.7 |
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Form of Certificate representing the 9.75% Series D Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on August 19, 2013).
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4.8 |
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Indenture, related to our 3.25% Convertible Senior Notes due 2026, dated December 6, 2006, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as Trustee (Incorporated by reference to Exhibit 4.12 of the Company’s Annual Report on Form 10-K (File No. 001-12719) for the year ended December 31, 2006).
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|
4.9 |
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Indenture, related to our 5.00% Convertible Senior Notes due 2029, dated as of September 28, 2009, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 30, 2009).
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4.10 |
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First Supplemental Indenture, related to our 5.00% Convertible Senior Notes due 2029, dated as of September 28, 2009, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 30, 2009).
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4.11 |
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Form of 5.00% Convertible Senior Note due 2029 (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 30, 2009).
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4.12 |
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Indenture (including the Form of Note), related to our 8.875% Senior Notes due 2019, dated as of March 2, 2011 among the Company, the Guarantor and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on March 8, 2011).
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4.13 |
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First Supplemental Indenture, related to our 3.25% Convertible Senior Notes due 2026, dated as of April 1, 2011 among Goodrich Petroleum Corporation and Goodrich Petroleum Company, L.L.C. and Wells Fargo Bank, National Association, as Trustee (Incorporated by reference to Exhibit 4.10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2012).
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4.14 |
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Second Supplemental Indenture, related to our 5.00% Convertible Senior Notes due 2029, dated as of April 1, 2011 among Goodrich Petroleum Corporation and Goodrich Petroleum Company, L.L.C. and Wells Fargo Bank, National Association, as Trustee (Incorporated by reference to Exhibit 4.11 of the Company’s Annual Report on Form 10-K (File No. 001-12719) for the year ended December 31, 2012).
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4.15 |
|
Third Supplemental Indenture, related to our 5.00% Convertible Senior Notes due 2032, dated as of August 26, 2013, between Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C. and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on August 27, 2013).
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4.16* |
|
Purchase Agreement, dated as of February 26, 2015, by and among the Company and Franklin Advisers, Inc., as investment manager on behalf of certain funds and accounts listed thereto.
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|
10.1 |
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Goodrich Petroleum Corporation 1995 Stock Option Plan (Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-4 (File No. 333-58631) filed May 30, 1995).
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10.2† |
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Goodrich Petroleum Corporation 2006 Long-Term Incentive Plan (Incorporated by reference to Annex B to the Company’s Proxy Statement on Schedule 14A (File No. 001-12719) filed April 17, 2006).
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10.3† |
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Goodrich Petroleum Corporation Annual Bonus Plan (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 8, 2007).
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10.4† |
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Non-Employee Director Compensation Summary (Incorporated by reference to Exhibit 10.49 of the Company’s Annual Report on Form 10-K (File No. 001-12719) for the year ended December 31, 2007).
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10.5† |
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Form of Subscription Agreement dated September 27, 1999 (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) dated October 15, 1999).
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10.6† |
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Form of Grant of Restricted Phantom Stock (1995 Stock Option Plan) (Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
|
84
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10.7† |
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Form of Grant of Restricted Phantom Stock (2006 Long-Term Incentive Plan) (Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
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10.8† |
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Form of Director Stock Option Agreement (with vesting schedule) (Incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
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10.9† |
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Form of Director Stock Option Agreement (immediate vesting) (Incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
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10.10† |
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Form of Incentive Stock Option Agreement (Incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
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10.11† |
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Form of Nonqualified Option Agreement (Incorporated by reference to Exhibit 4.7 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
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10.12† |
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Amended and Restated Severance Agreement between the Company and Walter G. Goodrich dated November 5, 2007 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 8, 2007).
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10.13† |
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Amended and Restated Severance Agreement between the Company and Robert C. Turnham, Jr. dated November 5, 2007 (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 8, 2007).
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10.14† |
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Amended and Restated Severance Agreement between the Company and Mark E. Ferchau dated November 5, 2007 (Incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 8, 2007).
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10.15 |
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Second Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas and certain lenders dated May 5, 2009 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 7, 2009).
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10.16 |
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First Amendment to Second Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas and certain lenders, dated as of September 22, 2009 (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 28, 2009).
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10.17 |
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Third Amendment to Second Amended and Restated Credit Agreement dated as of February 4, 2011 among Goodrich Petroleum Company, L.L.C., BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on February 10, 2011).
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10.18 |
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Second Amendment to Second Amended and Restated Credit Agreement dated as of October 29, 2010 among Goodrich Petroleum Company, L.L.C., BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on February 10, 2011).
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10.19 |
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Fourth Amendment to Second Amended and Restated Credit Agreement dated as of February 25, 2011 among Goodrich Petroleum Company, L.L.C.,BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on March 3, 2011).
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10.20 |
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Sixth Amendment to Second Amended and Restated Credit Agreement dated as of October 31, 2011 among Goodrich Petroleum Company, L.L.C., BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 4, 2011).
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10.21 |
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Fifth Amendment to Second Amended and Restated Credit Agreement dated as of May 16, 2011 among Goodrich Petroleum Company, L.L.C., BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 to the Company’s Annual Report on Form 10-K (File No. 001-12719) filed on February 24, 2012).
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85
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10.22 |
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Seventh Amendment to Second Amended and Restated Credit Agreement dated as of November 2, 2012 among Goodrich Petroleum Company, L.L.C., Well Fargo Bank, National Association, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 7, 2013).
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86
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10.23 |
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Eighth Amendment to Second Amended and Restated Credit Agreement dated as of March 13, 2013 among Goodrich Petroleum Company, L.L.C., Well Fargo Bank, National Association, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 7, 2013).
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10.24 |
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Ninth Amendment to Second Amended and Restated Credit Agreement dated as of October 25, 2013 among Goodrich Petroleum Company, L.L.C., Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 5, 2013).
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10.25 |
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Tenth Amendment to the Second Amended and Restated Credit Agreement dated May 19, 2014 among Goodrich Petroleum Company LLC. And Wells Fargo Bank National Association as administrative agent and the lenders thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on August 7, 2014). |
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10.26 |
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Eleventh Amendment to the Second Amended and Restated Credit Agreement dated August 4, 2014 among Goodrich Petroleum Company LLC. and Wells Fargo Bank National Association as administrative agent and the lenders thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 6, 2014).
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10.27 |
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Twelfth Amendment to the Second Amended and Restated Credit Agreement dated September 30, 2014 among Goodrich Petroleum Company LLC. and Wells Fargo Bank National Association as administrative agent and the lenders thereto(Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 6, 2014).
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10.28† |
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Director Compensation Agreement between Patrick E. Malloy and Goodrich Petroleum Corporation dated June 1, 2013. (Incorporated by reference to Exhibit 10.28 of the Company’s Annual Report on Form 10-K (File No. 001-12719) for the year ended December 31, 2013).
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12.1* |
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Ratio of Earnings to Fixed Charges.
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12.2* |
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Ratio of Earnings to Fixed Charges and Preference Securities Dividends.
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21.1* |
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Subsidiary of the Registrant:
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|
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Goodrich Petroleum Company L.L.C.—Organized in the State of Louisiana.
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23.1* |
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Consent of Ernst & Young LLP—Independent Registered Public Accounting Firm.
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23.2* |
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Consent of Netherland, Sewell & Associates, Inc.
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23.3* |
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Consent of Ryder Scott Company.
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31.1* |
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Certification by Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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31.2*
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Certification by Chief Financial Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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32.1** |
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Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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32.2** |
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Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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99.1* |
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Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.
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99.2* |
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Report of Ryder Scott Company, Independent Petroleum Engineers and Geologists.
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101.INS* |
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XBRL Instance Document |
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101.SCH* |
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XBRL Schema Document
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101.CAL* |
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XBRL Calculation Linkbase Document
|
87
|
101.LAB* |
|
XBRL Labels Linkbase Document
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101.PRE* |
|
XBRL Presentation Linkbase Document
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101.DEF* |
|
XBRL Definition Linkbase Document
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|
|
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* |
Filed herewith. |
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** |
Furnished herewith. |
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† |
Denotes management contract or compensatory plan or arrangement. |
88
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, on February 27, 2015.
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GOODRICH PETROLEUM CORPORATION
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||
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By: |
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/s/ WALTER G. GOODRICH |
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Walter G. Goodrich Chief Executive Officer |
POWER OF ATTORNEY
Each person whose signature appears below hereby constitutes and appoints Walter G. Goodrich and Jan L. Schott and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report of Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities indicated on February 27, 2015.
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Signature |
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Title |
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/s/ WALTER G. GOODRICH
Walter G. Goodrich |
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Vice Chairman, Chief Executive Officer and Director (Principal Executive Officer) |
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/S/ JAN L. SCHOTT
Jan L. Schott |
|
Senior Vice President and Chief Financial Officer (Principal Financial Officer) |
|
/S/ PATRICK E. MALLOY, III
Patrick E. Malloy, III |
|
Chairman of Board of Directors |
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/S/ ROBERT C. TURNHAM, JR.
Robert C. Turnham, Jr. |
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President, Chief Operating Officer and Director |
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/S/ Robert T. Barker
Robert T. Barker |
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Controller and Principal Accounting Officer |
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/S/ JOSIAH T. AUSTIN
Josiah T. Austin |
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Director |
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/S/ PETER D. GOODSON
Peter D. Goodson |
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Director |
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/S/ MICHAEL J. PERDUE
Michael J. Perdue |
|
Director |
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/S/ ARTHUR A. SEELIGSON
Arthur A. Seeligson |
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Director |
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/S/ STEPHEN M. STRATY
Stephen M. Straty |
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Director |
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/S/ GENE WASHINGTON
Gene Washington |
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Director |
89
