UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

For the fiscal year ended December 31, 2015

OR

Commission file number: 001-12719

 

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

 

(Registrant’s telephone number, including area code) (713) 780-9494

Securities Registered Pursuant to Section 12(b) of the Act:

 

Securities Registered Pursuant to Section 12(g) of the Act:

5.375% Series B Cumulative Convertible Preferred Stock, par value $1.00 per share

Depositary Shares, Each Representing 1/1000 Interest of 10.00% Series E Cumulative Convertible 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.

 

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, held by non-affiliates (based upon the closing sales price on the New York Stock Exchange on June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $99.2 million. The number of shares of the registrant’s common stock outstanding as of March 23, 2016 was 78,063,640.

Documents Incorporated By Reference:

Certain information called for in Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference to the registrant’s definitive proxy statement for its annual meeting of stockholders, or will be included in an amendment to this Annual Report on Form 10-K.

 

 

 

 

 

 

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GOODRICH PETROLEUM CORPORATION

ANNUAL REPORT ON FORM 10-K

FOR THE FISCAL YEAR ENDED

December 31, 2015

 

 

 

 

 

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PART I

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)  Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, and (iii) South Texas, which includes the Eagle Ford Shale Trend. We own interests in 193 producing oil and natural gas wells located in 43 fields in eight states. At December 31, 2015, we had estimated proved reserves of approximately 9.1 MMBoe, comprised of 31.9 Bcf of natural gas and 3.8 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.

Liquidity and Ability to Continue as a Going Concern

As discussed under “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources,” continued low oil and natural gas prices during 2015 and into 2016 have had a significant adverse impact on our business, and, as a result of our financial condition, substantial doubt exists that we will be able to continue as a going concern.

As of March 29, 2016, the total outstanding principal amount of our debt obligations was $439.2 million, consisting of the following:

In addition, we have outstanding four separate classes of preferred stock with an aggregate liquidation preference of $273.5 million.

As a result of the continued low commodity price environment, our cash flow from operations has substantially declined and the price of our common stock has declined significantly.  On January 13, 2016, the New York Stock Exchange (the “NYSE”) formally commenced delisting procedures for our common stock due to our abnormally low trading price. On January 21, 2016, the NYSE filed a Form 25 with the Securities and Exchange Commission (the “SEC”), notifying us of the removal of our common stock from listing.

We recently borrowed $10.0 million under the Senior Credit Facility, which represented substantially all of the remaining undrawn amount under the Senior Credit Facility. These funds are intended to be used for general corporate purposes. As a result of existing defaults under the Senior Credit Facility, we are unable to make any further draws on the Senior Credit Facility, unless the defaults are waived by the lenders.

We also recently announced that we were exercising our rights to a grace period with respect to (i) an aggregate $12.5 million in interest payments that were due on March 15, 2016 on our 2019 Notes, 8.0% Second Lien Notes and 8.875% Second Lien Notes and (ii) an aggregate $2.6 million in interest payments that are due on April 1, 2016 on our 2029 Notes, 2032 Notes and 2032 Exchange Notes.  These grace periods permit us 30 days to make the interest payments before an event of default occurs under the respective indentures governing the notes. Despite the 30-day grace period and an event of default has not occurred, accounting principles

 

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generally accepted in the United States (“US GAAP”) requires us to classify amounts outstanding under these notes and the Senior Credit Facility as current liabilities as of December 31, 2015.

The precipitous decline in oil and natural gas prices during 2015 and into 2016 has had a significant adverse impact on our business, and as a result of our financial condition, our registered independent public accountants have issued an opinion with an explanatory paragraph expressing substantial doubt as to our ability to continue as a “going concern.” As a result, we are in default under the Senior Credit Facility as of the date hereof. As a result of the default, we are unable to make further draws on the Senior Credit Facility unless the default is waived by the lenders under our Senior Credit Facility. We are currently in discussions with the lenders under our Senior Credit Facility regarding a waiver of this requirement. If we do not obtain a waiver of this requirement within 15 days, an event of default will exist under the Senior Credit Facility and the lenders under the Senior Credit Facility will be able to accelerate the repayment of debt under the Senior Credit Facility. Furthermore, if we are unable to restructure our current obligations under our existing outstanding debt and preferred stock instruments, and address near-term liquidity needs, we may need to seek relief under the U.S. Bankruptcy Code. This relief may include: (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of our assets pursuant to section 363(b) of the U.S. Bankruptcy Code and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization (where votes for the plan may be solicited from certain classes of creditors prior to a bankruptcy filing) that we would seek to confirm (or “cram down”) despite any classes of creditors who reject or are deemed to have rejected such plan; or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.

Under certain circumstances, it is also possible that our creditors may file an involuntary petition for bankruptcy against us. Please read “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for further discussion. Also, for additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences of our failure to do so, please see “Item 1A—Risk Factors.”

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.

 

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

As used herein, the following terms have specific meanings as set forth below:

 

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.

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.

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).

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.

 

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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.

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 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.

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 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.

 

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Oil and Natural Gas Operations and Properties

Overview. As of December 31, 2015, nearly all of our proved oil and natural gas reserves were located in Louisiana, Texas and Mississippi. We spent substantially all of our 2015 capital expenditures of $85.5 million in these areas, with $73.6 million, or 86%, spent on the TMS, $10.2 million, or 12% spent on the Haynesville Shale Trend and $1.6 million, or 2%, spent on the Eagle Ford Shale Trend. Our total capital expenditures, including accrued costs for services performed during 2015, consisted of $79.8 million for drilling and completion costs, $4.3 million for leasehold acquisitions and extensions and $1.4 million for facilities, infrastructure and equipment.

Beginning in the second half of 2014, commodity prices, particularly oil, began to decline sharply. The decline became precipitous late in the fourth quarter of 2014 and into 2015.  The duration and significant magnitude of this price decline has materially and adversely impacted our results of operations and led to substantial changes in our operating and drilling programs for the second half of 2015. As a result, during 2015, we focused on managing our balance sheet to reduce leverage and preserve liquidity during this low commodity price environment.

 

 

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The table below details our acreage positions, average working interest and producing wells as of December 31, 2015.

  

 

Tuscaloosa Marine Shale Trend

As of December 31, 2015, we have acquired approximately 359,000 gross (272,000 net) lease acres in the TMS, an emerging oil shale play in Southwest Mississippi and Southeast Louisiana. During 2015, we conducted drilling operations on 5 gross (3.9 net) wells and added 7 gross (5.7 net) wells to production in the TMS.

Haynesville Shale Trend

As of December 31, 2015, we have acquired or farmed-in leases totaling approximately 55,000 gross (27,000 net) acres in the Haynesville Shale. During 2015, we added 1 gross (1 net) well to production in the Angelina River Trend portion of our acreage position. Our Haynesville Shale Trend drilling activities are located in leasehold areas in East Texas and Northwest Louisiana.

Eagle Ford Shale Trend

As of December 31, 2015, we have acquired or farmed-in leases totaling approximately 36,000 gross (17,000 net) lease acres. As part of our efforts in 2015 to reduce leverage and preserve liquidity, we sold all of our proved reserves in the Eagle Ford Shale Trend and a portion of the associated leasehold. We retained 17,000 net acres of undeveloped acreage in the Eagle Ford Shale Trend. We closed the Eagle Ford Shale Trend sale on September 4, 2015.

Other

As of December 31, 2015, we maintained ownership interests in acreage and/or wells in several additional fields, including the Longwood field in Caddo Parish, Louisiana 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 in the TMS, Haynesville Shale Trend and Eagle Ford Shale Trend.

 

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Oil and Natural Gas Reserves

The following tables set forth summary information with respect to our proved reserves as of December 31, 2015 and 2014, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) and by Ryder Scott Company (“RSC”) our independent reserve engineers. Approximately 58% and 42% of the proved reserves estimates shown herein at December 31, 2015 have been independently prepared by NSAI and RSC, respectively. NSAI prepared the estimates on all our proved reserves as of December 31, 2015 on properties other than those located in the TMS. RSC prepared the estimate of proved reserves as of December 31, 2015 for our TMS properties. Copies of the summary reserve reports of NSAI and RSC as of December 31, 2015 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 “Item 8—Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

Proved undeveloped reserves were not included in our December 31, 2015 reserve estimates as the sustained decline in oil and natural gas prices has raised substantial doubt about our ability to continue as a going concern and our ability to adequately finance the development of proved undeveloped reserves in the future.

 

 

 

 

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The following table presents our reserves by targeted geologic formation in MBoe.

 

 

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 2015 through December 2015, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For reserves at December 31, 2015, the average twelve month prices used were $2.58 per MMBtu of natural gas and $50.28 per Bbl of crude. 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, 2015 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.

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.

 

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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, 2015, as estimated by NSAI and RSC, were 9.1 MMBoe, consisting of 31.9 Bcf of natural gas and 3.8 MMBbls of oil and condensate. In 2015 we added approximately 2.3 MMBoe related to our drilling activities in the TMS and Haynesville Shale Trend. We had negative revisions of approximately 26.1 MMBoe, divestitures of 9.9 MMBoe and produced 2.7 MMBoe in 2015. The vast majority of our negative revisions related to the removal of 24.8 MMBoe of proved undeveloped reserves out of the proved category.

We did not report any proved undeveloped reserves at December 31, 2015. We had negative revisions of 24.8 MMBoe and we did not develop any of our total proved undeveloped reserves booked as of December 31, 2014.

Productive Wells

The following table sets forth the number of productive wells in which we maintain ownership interests as of December 31, 2015:

 

 

 

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.

 

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Acreage

The following table summarizes our gross and net developed and undeveloped acreage under lease as of December 31, 2015. Acreage in which our interest is limited to a royalty or overriding royalty interest is excluded from the table.

 

 

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 oil or natural gas, 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 oil or natural gas is produced.

Lease Expirations

We have undeveloped lease acreage, excluding optioned acreage, that will expire during the next four years, unless the leases are converted into producing units or extended prior to lease expiration. All costs related to the leased acreage below have been written-off as of December 31, 2015. The following table sets forth the lease expirations as of December 31, 2015:

 

 

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.

 

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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.

 

 

At December 31, 2015, we had 2 gross (1.7 net) development wells waiting to be 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, 2015), 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, 2015. See “Item 6—Selected Financial Data” and “Item 8—Financial Statements and Supplementary Data” of this Form 10-K for disclosure of revenues, profits and total assets for the years ended December 31, 2015, 2014 and 2013.

 

 

 

 

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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, 2015, 2014 and 2013 are as follows:

 

 

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 March 23, 2016, we had 51 full-time employees in our Houston administrative office and our one field office, none of whom is represented by any labor union. 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.  

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. Environmental laws and regulations also impose certain plugging and abandonment and site reclamation requirements. 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 consequently affects profitability. Additionally, the trend in environmental regulation has been to place more restrictions and

 

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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. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future.

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. Wastes, including drilling fluids and produced water, generated in the exploration or production of oil and natural gas are exempt from classification as hazardous wastes under RCRA. Proposals have been made from time to time to eliminate this exemption, which, if adopted, would cause some of these wastes to be regulated under the more rigorous RCRA hazardous waste standards. A loss of this RCRA exemption could result in increased costs to us and the oil and gas industry in general to manage and dispose of generated wastes. Moreover, some ordinary industrial wastes which we generate, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous wastes if they have hazardous characteristics.

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 undertake costly site investigations, 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. In September 2015, new EPA and U.S. Army Corps of Engineers (the “Corps”) rules defining the scope of the EPA’s and the Corps’ jurisdiction became effective. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. The process for obtaining permits has the potential to delay the

 

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development of natural gas and oil projects. 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 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 natural gas and oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. For example, the EPA has taken the following actions and issued: guidance under the SDWA for hydraulic fracturing activities involving the use of diesel fuel; final regulations under the federal Clean Air Act governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; an advanced notice of proposed rulemaking in March 2014 under the Toxic Substances Control Act that would require companies to disclose information regarding the chemicals used in hydraulic fracturing; and proposed rules in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.

Various state and federal agencies are studying the potential environmental impacts of hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These or future studies could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act 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,

 

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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, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, in 2012, the EPA issued federal regulations requiring the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” 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 significantly.

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 a variety of sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis. More recently, in December 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. These changes to EPA’s GHG emissions reporting rule could result in increased compliance costs. Also, in August 2015, the EPA announced proposed rules that would establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, as part of an overall effort to reduce methane emissions by up to 45 percent by 2025. 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

 

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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.  

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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Oil prices and natural gas prices have declined substantially from historical highs and may remain depressed for the foreseeable future. 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 depends 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 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. High and low spot prices for New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude oil and NYMEX Henry Hub natural gas between February 2015 and the date of this annual report were as follows:

 

 

Average oil and natural gas prices varied substantially during the past few years. Any actual or anticipated reduction in natural gas and crude oil 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. 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

 

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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 Senior Credit Facility, which would restrict our liquidity. Additionally, further or continued declines in prices could result in additional 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 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:

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.

 

A sustained depression of oil and natural gas prices can continue to 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.

 

The current low commodity price environment has had a significant, adverse impact on us. As of December 31, 2015, we had $470.6 million in indebtedness and declining cash flows from operations due to the decline in oil and natural gas prices and the roll off of our crude oil hedging arrangements. Our ability to service our debt, including the unsecured notes and second lien notes, and fund our operations is at risk in a sustained continuation of the current commodity price environment. 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.

 

 

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Due to our substantial liquidity concerns, we may be unable to continue as a going concern.

Our existing and future debt agreements could create issues as interest payments become due and the debt matures that will threaten our ability to continue as a going concern. For example, absent any action with respect to the repayment or refinancing of our existing indebtedness or any waivers or amendments to the agreements governing our existing indebtedness, our Senior Credit Facility will mature on February 24, 2017. As of the date of this filing, total lender commitments under our Senior Credit Facility are $40.3 million on which we had $27.0 million drawn on December 31, 2015 under the Senior Credit Facility. Additionally, the borrowing base under our Senior Credit Facility is subject to at least semi-annual redetermination on April 1 and October 1, and as a result, availability thereunder, could be reduced and advances in excess of the new availability would need to be repaid. The next semi-annual redetermination of the borrowing base is scheduled for April 1, 2016. We also have substantial interest payments due on our unsecured notes and second lien notes beginning in March 2016. If we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in the debt agreements governing our indebtedness, an event of default could result, which would permit acceleration of such debt and which could result in an event of default under and an acceleration of our other debt and would permit our secured lenders to foreclose on any of our assets securing such debt. Any accelerated debt would become immediately due and payable. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or otherwise extend the maturity dates, and to cure any potential defaults, there is no assurance that any particular actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient. The uncertainty associated with our ability to repay our outstanding debt obligations as they become due raises substantial doubt about our ability to continue as a going concern.

 

The report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern. As a result, we are in default under our Senior Credit Facility.

 

Our Senior Credit Facility requires that our annual financial statements include a report from our independent registered public accounting firm with an unqualified opinion without an explanatory paragraph as to going concern. The report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern. Per the terms of our agreement, we are in default under our Senior Credit Facility. As a result of the default, we are unable to make further draws on the Senior Credit Facility unless the default is waived by the lenders under our Senior Credit Facility. We are currently in discussions with the lenders under our Senior Credit Facility regarding a waiver of this requirement. If we do not obtain a waiver of this requirement within 15 days, an event of default will exist under the Senior Credit Facility and the lenders under the Senior Credit Facility will be able to accelerate the repayment of debt under the Senior Credit Facility. Any acceleration of our debt obligations under the Senior Credit Facility would result in a potential foreclosure on the collateral securing the Senior Credit Facility and would trigger cross-default provisions under our other financing agreements.

 

If we are unable to complete the Recapitalization Plan and address our near-term liquidity needs, we may not be able to make our interest payments on our unsecured notes and second lien notes, at which time we are likely to need to seek relief under the U.S. Bankruptcy Code. If we seek bankruptcy relief, we expect that our common stockholders, preferred stockholders and general unsecured creditors would likely receive little or no consideration for their securities.

 

We believe that the substantial reduction in our cash interest expense contemplated by the Recapitalization Plan is critical to our continuing viability. We were not able to make our interest payments on our unsecured notes and second lien notes on March 15, 2016 and elected to exercise our right to a 30-day grace period for the interest payments due on both March 15, 2016 and April 1, 2016.  If we are unable to complete the Recapitalization Plan and address our near-term liquidity needs, we will likely not be able to make these interest payments and we are likely to need to seek relief under the U.S. Bankruptcy Code. A chapter 11 case would have a significant impact on our business. It is impossible for us to predict with certainty the amount of time needed in order to complete an in-court restructuring. If we seek to implement a plan of reorganization under the U.S. Bankruptcy Code, we will need to negotiate agreements with our constituent parties regarding the terms of such plan and such negotiations could take a significant amount of time. A lengthy chapter 11 case would involve significant additional professional fees and expenses and divert the attention of management from operation of the business, as well as create concerns for customers, employees and vendors. There is a risk, due to uncertainty about the future, that (i) employees could be distracted from performance of their duties or attracted to other career opportunities; (ii) our ability to enter into new contracts or to renew existing contracts and compete for new business may be adversely affected; and (iii) we may not be able to obtain the necessary financing to sustain us during the chapter 11 case.

 

In addition, to successfully complete a restructuring under the U.S. Bankruptcy Code, we would require debtor-in-possession financing, the most likely source of which would be our existing lenders. If we were unable to obtain financing in a bankruptcy case or

 

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any such financing was insufficient to fund operations pending the completion of a restructuring, there would be substantial doubt that we could complete a restructuring.

 

Furthermore, assuming we are able to develop a plan of reorganization, we may not receive the requisite acceptances to confirm such a plan and, even if the requisite acceptances of the plan are received, the Bankruptcy Court may not confirm the plan. If we are unable to develop a plan of reorganization that can be accepted and confirmed, or if the Bankruptcy Court otherwise finds that it would be in the best interest of creditors, or if we are unable to obtain appropriate financing, our chapter 11 case may be converted to a case under chapter 7 of the U. S. Bankruptcy Code, pursuant to which a trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the U.S. Bankruptcy Code.

 

As a result of the foregoing, if we seek bankruptcy relief, we expect that holders of our common stock, preferred stock and unsecured senior notes would likely receive little or no consideration for their securities. In particular, we believe that liquidation under chapter 7 of the U.S. Bankruptcy Code would likely result in no distributions being made to our shareholders or to our general unsecured creditors.

 

Even if we are able to complete the Recapitalization Plan, we may still be unsuccessful in our operating plan, particularly if oil and natural gas prices do not recover. If we are not successful in executing our current plan for operations, we may need to seek relief under the U.S. Bankruptcy Code notwithstanding the success of the Recapitalization Plan. If we seek bankruptcy relief, we expect that holders of our common stock, preferred stock and any unsecured notes that remain outstanding would likely receive little or no consideration.

 

Even if the Recapitalization Plan is successful, but oil and natural gas prices do not recover or if we are not able to execute our current plan for operations, then we may need to seek relief under the U.S. Bankruptcy Code notwithstanding the completion of the Recapitalization Plan. If we were to seek relief under the U.S. Bankruptcy Code notwithstanding the completion of the Recapitalization Plan, we expect that the holders of our shares of our common stock and any unsecured notes or preferred stock remaining outstanding after the Exchange Offers would likely receive little or no consideration for their securities.

 

Our substantial indebtedness, liquidity issues and the potential for restructuring transactions, including the Recapitalization Plan, may impact our business, financial condition and operations.

 

Due to our substantial indebtedness, liquidity issues and the potential for restructuring transactions, including the Recapitalization Plan, there is risk that, among other things:

 

The occurrence of certain of these events has already negatively affected our business and may continue to have a material adverse effect on our business, results of operations and financial condition.

 

We may be unable to maintain compliance with certain financial ratio covenants of our outstanding indebtedness which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.

Our 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, 2015, we were not in compliance with all the financial covenants of our Senior Credit Facility and did not receive a waiver from our lenders; furthermore, without the restructuring of our current obligations under our existing outstanding debt and preferred stock instruments, we anticipate that we will violate the First Lien Debt to EBITDAX financial covenant ratio under the Senior Credit Facility at the end of the third quarter of 2016. Such failures to comply with the conditions and covenants in our Senior Credit Facility that is not waived by our lenders or otherwise cured could lead to a termination of our Senior Credit Facility and acceleration of all amounts due under our Senior Credit Facility and trigger cross-default provisions under other financing

 

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agreements. 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. These restrictions may also limit our ability to obtain future financings to withstand a downturn in our business or the economy in general. We may also be prevented from taking advantage of business opportunities that arise. 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.

 

The consummation of the Unsecured Notes Exchange Offers and Second Lien Exchange Offers in connection with the Recapitalization Plan could result in significant federal income tax liabilities for us.

The consummation of the Unsecured Notes Exchange Offers and Second Lien Exchange Offers in connection with the Recapitalization Plan is expected to trigger a substantial amount of taxable income from the cancellation of indebtedness. While we anticipate being able to offset this income with current and prior net operating losses, under certain circumstances the amount of taxable income or alternative minimum taxable income could exceed the net operating losses available to offset such income in which case the consummation of the Unsecured Notes Exchange Offers and Second Lien Exchange Offers could result in our having significant federal income tax liabilities.

 

The price of our common stock has been volatile recently. This volatility may affect the price at which you could sell your common stock.

The market price for our common stock has varied between a high of $4.71 and a low of $0.05 between February 2015 and February 2016, respectively. This volatility may affect the price at which you can sell your common stock, and the sale of substantial amounts of our common stock could adversely affect the price of our common stock. Our stock price may continue to be volatile and subject to significant price and volume fluctuations in response to market and other factors, which may include:

 

Our common stock has been delisted by the NY SE

 

As a result of a precipitous decline in our stock price, on January 13, 2016, the NYSE formally commenced delisting procedures for our common stock due to our abnormally low trading price. On January 21, 2016, the NYSE filed a Form 25 with the SEC, notifying our removal from listing.

 

The delisting of our common stock has had an adverse effect on the market liquidity of our common stock and, as a result, the market price for our common stock could become more volatile. If we are unable to become re-listed on a national securities exchange and increase the market value per share of our common stock, it may be difficult to attract the interest of analysts, institutional investors, investment funds and brokers.

 

There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.

 

We are not restricted from issuing additional common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities, including outstanding options, or otherwise will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.

 

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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 2015. 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:

Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

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:

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.

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.

 

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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; plugging and abandonment and site reclamation requirements; 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, 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 natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. For example, the EPA has taken the following actions and issued: guidance under the SDWA for hydraulic fracturing activities involving the use of diesel fuel; final regulations under the federal Clean Air Act governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; an advanced notice of proposed rulemaking in March 2014 under the Toxic Substances Control Act that would require companies to disclose information regarding the chemicals used in hydraulic fracturing; and proposed rules in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.

Various state and federal agencies are studying the potential environmental impacts of hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These or future studies could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

 

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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 a variety of sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis. Recently, in December 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. These changes to EPA’s GHG emissions reporting rule could result in increased compliance costs. Also, in August 2015, the EPA announced proposed rules that would establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, as part of an overall effort to reduce methane emissions by up to 45 percent by 2025. 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 $494.5 million, $354.8 million, $36.3 million, $63.7 million, and $17.1 million for the years ended December 31, 2015, 2014, 2013, 2012 and 2011, 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.

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

 

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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, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.  If any of our swaps do not qualify for the commercial end-user exception, 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 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 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.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and 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 U.S. 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 and state 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 affect our financial condition and results of operations. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction.  Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil.  This fee would be collected on domestically produced and imported petroleum products.  The fee would be phased in evenly over five years, beginning October 1, 2016.  The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.

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 have historically used 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 48% (0% of natural gas production and approximately 96% of oil production) of our total production volumes for the year ended December 31, 2015.

 

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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, 2015, we received cash receipts to settle our derivative contracts totaling $54.3 million, while we received $3.4 million to settle our derivative contracts for the year ended December 31, 2014. At December 31, 2015, we had a de minimis liability derivative position related to our derivative contracts compared to a net asset derivative position of $46.9 million at December 31, 2014. 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 swap and call derivative contracts 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 “Item 8—Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

Oil and natural gas prices are volatile. All of our crude oil hedging contracts expired in 2015. If we choose not to or are unable to replace our hedges, our cash flows from operations will be subjected to increased volatility.

We have historically entered into hedging transactions for our oil and natural gas production revenues to reduce our exposure to fluctuations in the price of oil and natural gas. All of our crude oil hedging contracts expired in 2015. As a result, more of our future production will be sold at market prices, exposing us to the fluctuations in the price of oil and natural gas, unless we enter into additional hedging transactions. We may choose not to or be unable to replace our hedges, which will subject our cash flows from operations to increased volatility.

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 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. At December 31, 2015, we did not have any proved undeveloped reserves, while 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.

 

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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, 2015 and 2014, we recorded impairments related to oil and natural gas properties of $452.0 million and $331.9 million, respectively. The decline in oil and natural gas prices precipitated the loss of estimated proved reserves for our oil and natural gas producing properties. Additionally, the prospect of lower future prices has raised substantial doubt about our ability to continue as a going concern consequently all estimated proved undeveloped reserves have been excluded from our estimated total proved reserves as of December 31, 2015 and the carrying cost of the related undeveloped leasehold was impaired in 2015.

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, 2015 were associated with our Louisiana, Texas and Mississippi properties which include the TMS and the Haynesville Shale Trend. 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. As of December 31, 2015, approximately 33% of our reserves and approximately 29% of our sales volumes were attributable to non-operated properties. We have less ability to influence or control the operation or future development of these non-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 TMS Trend and (ii) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend. A number of companies are currently operating in the Haynesville 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

 

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production at significantly lower prices than those quoted on 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.

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, 2015, 2014 and 2013 were 74%, 62% and 71%, respectively. Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be 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, 2015, 2014 and 2013 are as follows:

 

 

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

 

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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:

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:

 

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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 “Item 8—Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

Not Applicable.

 

 

 

 

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PART II

 

Market Price of Our Common Stock

Our common stock was traded on the New York Stock Exchange (“NYSE”) under the symbol “GDP” throughout 2015.  In January 2016 our common stock was delisted from the NYSE due to abnormally low price levels.  As of January 2016 our common stock is being traded on the OTC Markets marketplace (“OTC”) under the symbol “GDPM”.

At March 23, 2016, the number of holders of record of our common stock was 1,093 and 78,063,640 shares were outstanding. High and low sales prices for our common stock for each quarter during 2015 and 2014 as reported on the NYSE were as follows:

 

 

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. In addition, our Senior 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” in this Annual Report on Form 10-K.

Issuer Repurchases of Equity Securities

We made no open market repurchases of our common stock for the year ended December 31, 2015.

For information on securities authorized for issuance under our equity compensation plans, see “Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

Unregistered Sales of Equity Securities

None that have not been previously reported by us on a Current Report on Form 8-K.

 

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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, 2010 and its relative performance is tracked through December 31, 2015.

 

 

 

 

 

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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.

 

 

 

 

 

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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—Financial Statements and Supplementary Data”, and the information set forth in “Item 1A—Risk Factors”.

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 Trend (“TMS”), (ii) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, and (iii) South Texas, which includes the Eagle Ford Shale Trend.

We seek to increase shareholder value by growing our oil and natural gas reserves, production revenues and cash flow from operating activities (“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 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.

Key Developments

The following general economic developments and corporate actions in 2015 and 2016 had and may continue to have a significant impact on our financial position and results of operations:

The Current, Sustained Low Commodity Price Environment

Beginning in the second half of 2014, commodity prices, particularly crude oil, began to decline sharply. The decline became precipitous late in the fourth quarter of 2014 and into 2015.  Crude oil prices declined from a high of over $105 per barrel in June 2014 to less than $27 per barrel in February 2016. Natural gas prices faced similar downward pressure in 2015, dropping below $1.70 per MMBtu in December 2015. As an exploration and production company with interests in unconventional oil and natural gas shale properties that require large investments of capital to develop, the significant magnitude of this price decline has had a particularly material and adverse impact on our results of operations and led to substantial changes in our operating and drilling programs.

In response to the decline in commodity prices, we focused on managing our balance sheet to reduce leverage and preserve liquidity during this extended low commodity price environment. Specifically, we took the following steps in 2015 to mitigate the effects of lower crude oil prices on our operations and conserve capital:

 

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As a result of the continued low commodity price environment, our cash flow from operations has substantially declined and the stock price of our common stock has declined significantly. On January 13, 2016, the NYSE formally commenced delisting procedures for our common stock due to our abnormally low trading price. On January 21, 2016, the NYSE filed a Form 25 with the SEC, notifying us of the removal of our common stock from listing.

The extended low commodity price environment has likewise significantly impacted our liquidity as operating cash flow has declined and our lenders have reduced the borrowing capacity under our Senior Credit Facility.  We have taken the following steps in 2015 and 2016 to enhance liquidity:

Given the downturn in oil and natural gas prices, we have faced and expect to continue to face liquidity constraints.  Our cash flows are negatively impacted by lower realized oil and natural gas sales prices. As of December 31, 2015 we no longer had any oil derivative contracts in place. Given the current oil futures pricing, we currently have limited hedging opportunities; as a result, we do not anticipate having in place any derivative positions with respect to our 2016 anticipated oil and condensate sales volumes and thus expect further deteriorating realized sale prices if oil prices do not improve.

The significant decline in oil and natural gas prices also increases the uncertainty of the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market.  The prolonged period of depressed commodity prices has significantly impacted our estimated proved reserves as of December 31, 2015.  In addition, we recorded an asset impairment expense of $452.0 million in 2015, all estimated proved undeveloped reserves have been excluded from our estimated total proved reserves as of December 31, 2015 and the carrying cost of the related undeveloped leasehold was impaired in 2015.  If downward revisions of proved reserves occur in the future, we could have further increases in our DD&A rates and additional oil and natural gas property impairment charges. We are unable to predict the timing and amount of future reserve revisions, nor the impact such revisions may have on our future DD&A rates or oil and natural gas property impairments. Future declines in commodity prices and estimated proved reserves could lead to further reductions of our borrowing base under the Senior Credit Facility. Such reductions could prevent us from borrowing additional amounts under the Senior Credit Facility or, if the borrowing base were to be reduced below the then-outstanding borrowings, could require us to repay the shortfall and could otherwise limit our ability to obtain alternative financing.

Without the restructuring of our current obligations under our existing outstanding debt and preferred stock instruments, we anticipate that we will violate the First Lien Debt to EBITDAX financial covenant ratio under the Senior Credit Facility at the end of the third quarter of 2016. We could request a waiver of this covenant violation; however, there is no assurance a waiver will be granted. If a waiver is not granted, we would be in default under the Senior Credit Facility and the lenders under the Senior Credit Facility will be able to accelerate the repayment of debt under the Senior Credit Facility. Any acceleration of our debt obligations would result in a potential foreclosure on the collateral securing the Senior Credit Facility.

 

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On March 8, 2016, we announced that we are electing our rights to a grace period with respect to (i) an aggregate $12.5 million in interest payments that were due on March 15, 2016 on our 2019 Notes, 8.0% Second Lien Notes and 8.875% Second Lien Notes and (ii) an aggregate $2.6 million in interest payments that were due on April 1, 2016 on our 2029 Notes, 2032 Notes and 2032 Exchange Notes.  These grace periods permit us 30 days to make the interest payments before an event of default occurs under the respective indentures governing the notes. Our failure to pay interest within the grace periods provided by our indentures would result in an event of default under each of those indentures and the trustee or the holders could declare all amounts outstanding under those indentures to become immediately due and payable. Additionally, our failure to pay interest within the grace periods provided by our indentures would result in an event of default under the Senior Credit Facility and the lenders under the Senior Credit Facility will be able to accelerate the repayment of debt under the Senior Credit Facility.

Collectively, the factors discussed above raise substantial doubt about our ability to continue as a going concern. Furthermore, if we are unable to restructure our current obligations under our existing outstanding debt and preferred stock instruments, and address near-term liquidity needs, we may need to seek relief under the U.S. Bankruptcy Code. This relief may include: (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of the Company’s assets pursuant to section 363(b) of the U.S. Bankruptcy Code and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization (where votes for the plan may be solicited from certain classes of creditors prior to a bankruptcy filing) that the Company would seek to confirm (or “cram down”) despite any classes of creditors who reject or are deemed to have rejected such plan; or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks

The Recapitalization Plan

In response to the decline of our operating cash flow, on January 26, 2016, the Company launched a comprehensive plan to reduce its cost structure and improve its operating results, cash flow from operations, liquidity and financial condition (the “Recapitalization Plan”). The Recapitalization Plan consists of the following proposed transactions:

If successful, we believe the Recapitalization Plan would have several positive effects on the Company’s capital structure and the holders of our common stock, including: (i) the reduction in debt and preferred liquidation preference; (ii) the reduction of the Company’s fixed dividend obligations and the increase in the percentage of its capitalization that is common stock; (iii) the simplification of the Company’s capital structure and the elimination of the market overhang caused by the outstanding Preferred Stock and the liquidation preferences of the Preferred Stock; (iv) expected improvements in institutional investor interest in the Company’s common stock following the Recapitalization Plan due to an improved balance sheet and (v) the increased ability of the Company to address its near-term liquidity needs, including the material reduction of cash interest expense on the Company’s secured debt obligations and the increased likelihood of attracting new capital due to a significantly improved balance sheet.

We also believe the Recapitalization Plan, if successful, would have positive effects on the Company’s future results of operations, including: (i) the elimination of annual cash interest expense of between $15.9 million (assuming the minimum conditions to the Unsecured Notes Exchange Offers are met) and $16.7 million (assuming full participation in the Unsecured Notes Exchanges) due to the exchange and cancellation of the Unsecured Notes in the Unsecured Notes Exchange Offers; (ii) the elimination of annual interest expense for 2016 of between $13.9 million (assuming the minimum conditions to the Second Lien Exchange Offers are met) and $14.7 million (assuming full participation in the Second Lien Exchange Offers), due to the ability of the Company to pay interest on the Second Lien Notes in kind, rather than in cash and (iii) the elimination of fixed dividend obligations of between $12.3 million

 

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(assuming the minimum conditions to the Preferred Exchange Offers are met) and $24.5 million (assuming full participation in the Preferred Exchanges) due to the exchange and cancellation of Preferred Stock in the Preferred Stock Exchange Offers.

The Recapitalization Plan is intended to facilitate a proposed recapitalization of the Company in an effort to simplify its capital structure, preserve liquidity and increase its ability to comply with its debt instruments during the current decline in the oil and gas industry. The Exchange Offers are conditioned, among other things, on (i) the Company’s common shareholders approving an amendment to the Company’s Restated Certificate of Incorporation increasing the number of authorized shares of common stock to 400 million (the “Authorized Share Amendment Proposal”) and (ii) the satisfaction of certain minimum participation thresholds according to the terms of each of the Exchange Offers. The Company will hold a special meeting of stockholders on March 31, 2016 to approve the Authorized Share Amendment Proposal.

To date, the minimum participation thresholds under the terms of each of the Exchange Offers have not been met and the number of shares necessary to pass the Authorized Share Amendment Proposal have not been voted by proxy.  As such, there is a significant risk that the Recapitalization Plan will be unsuccessful.

If we are unable to complete the Recapitalization Plan and address our near term liquidity needs, we will not be able to make our interest payments within the grace period described above, at which time we are likely to seek relief under the U.S. Bankruptcy Code. In such an event, we expect that the holders of our unsecured senior notes, shares of preferred stock and shares of our common stock would receive little or no consideration.

2015 Financial and Operating Results included:

Tuscaloosa Marine Shale Trend

 

We held approximately 359,000 gross (272,000 net) acres in the TMS as of December 31, 2015. During 2015, we conducted drilling operations on approximately 5 gross (3.9 net) TMS wells. As of December 31, 2015, we had 2 gross (1.7 net) TMS wells drilled and waiting on completion. Our net production volumes from our TMS wells represented approximately 33% of our total equivalent production on a Boe basis and approximately 66% of our total oil production for the year ended December 31, 2015. During 2015, we spent $73.6 million in the TMS, which included $3.9 million for leasehold costs.

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 55,000 gross (27,000 net) acres as of December 31, 2015 producing from or prospective for the Haynesville Shale. Our net production volumes from our Haynesville Shale Trend wells represented approximately 44% of our total equivalent production on a Boe basis for 2015.

Eagle Ford Shale Trend

 

We closed the sale of our Eagle Ford Shale Trend proved reserves and a portion of the associated leasehold on September 4, 2015. Immediately prior to the sale, our net production volumes from the sold properties represented approximately 28% of our total equivalent production volumes for 2015 on a Boe basis. For the year ended 2015 our net production volumes from our Eagle Ford Shale Trend wells represented approximately 22% of our total equivalent production on a Boe basis and approximately 34% of our

 

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total oil production. We have retained approximately 17,000 net acres of our undeveloped leasehold in Frio County, Texas, all of which is prospective for future development or sale.

Results of Operations

For the year ended December 31, 2015, we reported net loss applicable to common stock of $409.9 million, or $7.28 per share (basic and diluted), on operating revenues of $77.7 million. This compares to net loss applicable to common stock of $382.9 million, or $8.62 per share (basic and diluted), for the year ended December 31, 2014 and 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. The largest change in net loss from 2014 to 2015 is operating revenues and impairment expense. Revenues were down due to significantly lower realized oil and natural gas sales prices as well as lower oil, condensate and natural gas production volumes stemming from asset sales in December 2014 and September 2015.  Impairment expense of $452.0 million was recorded in 2015, which is an increase of approximately $120.0 million when compared to the impairment expense recognized 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.

 

 

Oil and Natural Gas Revenue

Natural gas, oil and condensate revenues decreased in 2015 compared to 2014 reflecting a decrease in our average realized sales prices for natural gas, oil and condensate and a reduction in natural gas, oil and condensate production. The decreases in natural gas, oil and condensate realized sales prices compared to 2014 contributed $99.7 million to the decrease in natural gas, oil and condensate revenue, while the decreased in natural gas, oil and condensate production contributed $29.8 million to the decrease in natural gas, oil and condensate revenue.

The difference between our average realized prices inclusive of net cash derivative settlements in the years ended December 31, 2015 and 2014 relates to our oil and natural gas swap contracts. There were no natural gas derivative contract settlements during 2015.  During 2014, we had natural gas derivative contract settlements covering 30,000 MMBtus per day at an average floor price of $4.76 per MMBtu. During 2015, we had an average of 3,500 Bbls per day hedged at an average fixed price of $96.11 per Bbl. During 2014, we had an average of 3,800 Bbls per day hedged at an average fixed price of $93.65 per Bbl.

 

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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.  

Operating Expenses

Operating expenses increased by $8.8 million in 2015 compared to 2014, due to higher asset impairment and exploration expenses partially offset by overall expense reductions due to the sale of our non-core East Texas natural gas fields in December 2014 and the sale of our Eagle Ford Shale Trend proved reserves in September 2015. Also offsetting the increase in operating expense was the recognition of a gain on the sale of assets primarily associated with the sale of our Eagle Ford Shale Trend proved reserves and a portion of the associated leasehold on September 4, 2015.

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.

 

 

Lease Operating Expense

Our lease operating expense (“LOE”) during 2015 decreased in comparison to 2014. The decrease was the result of an $8.1 million decrease in operating costs stemming from the sale of our non-core East Texas natural gas fields in December 2014 and a $6.3 million decrease from Eagle Ford Shale Trend properties sold in September 2015. These decreases were partially offset by a $0.4 million increase in operating costs associated with the continued development of the TMS in 2015. LOE in 2015 included workover expense of $1.3 million which added $0.50 per Boe to unit expense.  

Our LOE during 2014 included an expense of $4.3 million in workover costs which added $1.03 per Boe to LOE. Our LOE during 2013 included $6.0 million in workover costs which added $1.32 per Boe 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 generally trended higher as we added 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.

 

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Production and Other Taxes

Production and other taxes for the year ended 2015 included production tax of $2.3 million and ad valorem tax of $2.3 million. Production and other taxes decreased in 2015 due to significantly lower crude oil prices, lower oil production from our Eagle Ford Shale Trend wells prior to them being sold in September 2015 and lower tax rates on the TMS wells we have drilled. 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 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 Trend wells and lower tax rates on the TMS wells drilled in the state of Mississippi after July 1, 2013.

Transportation and Processing

Transportation and processing expense decreased in 2015 compared to 2014. The decrease is due to lower operated natural gas production, as our natural gas production incurs substantially all of our transportation and processing cost. The lower natural gas production is directly associated with the sale of our non-core East Texas natural gas fields in December 2014 and the sale of our Eagle Ford Shale Trend producing properties in September 2015.

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.

Exploration

Exploration expense increased in 2015 compared to 2014 as a result of lease expirations and undeveloped leasehold cost write-offs related to our TMS acreage. We did not renew TMS leases on acreage outside our core area as they expired in 2015 and determined that lease acreage expiring in 2016 outside our core area will not be renewed. Exploration expense in 2015 also included well location cost incurred on which operations have been suspended.

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.

 

NM – Not meaningful.

Depreciation, Depletion & Amortization (“DD&A”)

DD&A expense decreased in 2015 compared to 2014, due to the sale of our Eagle Ford Shale Trend producing properties in September 2015, the absence of our East Texas assets sold in December 2014 and the effect of the asset impairments taken in 2014

 

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which lowered 2015 DD&A rates. The decreases from the sold properties were partially offset by a 19% increase in TMS production volumes associated with the continued development of the TMS play in 2015.

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.

Impairment

We recorded asset impairment expense of $452.0 million in 2015. The decline in oil and natural gas prices precipitated the loss of estimated proved reserves for our oil and natural gas producing properties. Additionally, the prospect of lower future prices has raised substantial doubt about our ability to continue as a going concern consequently all estimated proved undeveloped reserves have been excluded from our estimated total proved reserves as of December 31, 2015 and the carrying cost of the related undeveloped leasehold was impaired in 2015.  We impaired our carrying cost in our Haynesville Shale Trend by $135.6 million and our TMS properties by $310.2 million during the third and fourth quarters of 2015.

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.

General and Administrative Expense (“G&A”)

G&A expense decreased in 2015 compared to 2014. The decrease stems from lower compensation expense, professional fees and share based compensation. We have reduced our staff headcount by more than 30% from year-end 2014 levels during 2015. The higher rate per Boe for 2015 reflects a 37% reduction in oil and natural gas production during 2015. Share-based compensation expense, which is a non-cash item, for 2015 totaled $6.7 million, a $2.9 million decrease from the 2014 total.

Although the rate per Boe 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 Boe 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.

 

(Gain) loss on Sale of Assets

In 2015 we recognized a $53.5 million gain on sale of assets.  The 2015 gain is almost entirely associated with the sale of our proved reserves and a portion of the associated leasehold in the Eagle Ford Shale Trend located in La Salle and Frio counties in south Texas.

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.

Other Income (Expense)

 

 

 

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Interest Expense

 

The increase in interest expense for 2015 is primarily the result of the issuance of $100 million in 8.0% Second Lien Notes in March 2015, the 2032 Exchange Notes in September 2015 and the 8.875% Second Lien Notes issued in October 2015. These increases were partially offset by decreases in interest expense for the 2029 Notes, 2019 Notes and 2032 Notes as a result of the 2014 note repurchases and 2015 note exchanges. Non-cash interest of $12.4 million is included in the interest expense reported for the year ended 2015 compared to $10.0 million for the year ended 2014. The increase in non-cash interest reflects the debt discount amortization on the 8.0% Second Lien Notes issued in March 2015.

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 2029 Notes for our 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 $10.0 million is included in the interest expense reported for the year 2014.

 

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. We do not designate our derivatives as hedges; consequently the settlements and changes in fair value are included in our Consolidated Statement of Operations.

Gain on derivatives was $7.4 million for 2015.  The gain includes net cash receipts of $54.3 million off set by the decrease in the fair value of $46.9 million. There were no natural gas derivative contract settlements during 2015.  The decrease in the fair value consists of a $0.5 million gain on our natural gas derivatives and a $47.4 million loss on our oil derivatives. The decrease in fair value of our oil derivatives reflects settled contracts and the ultimate expiration of all of our oil derivative contracts in December 2015.  The gain on our the natural gas derivative contracts is reflective of the portion of such contracts that expired during 2015 and the decline in natural gas futures prices in the latter half of 2015.

Gain on derivatives 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 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.

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.

 

Gain(loss) on Extinguishment of Debt

 

On October 1, 2015 we exchanged $158.2 million of our 2019 Notes for $75.0 million of new 8.875% Second Lien Notes. We accounted for this transaction as a troubled debt restructure and recognized a gain on extinguishment of debt of $62.6 million.

 

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 value 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.

 

 

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Income Tax Benefit

 

We recorded no income tax benefit for the years 2015, 2014 and 2013. 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, 2015.

 

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 natural 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 (loss), 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.

 

 

 

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 natural 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 2015 were cash flow from operating activities, proceeds from our common stock offering, proceeds from our second lien note issuances, borrowings under our Senior Credit Facility and proceeds from the sale of our Eagle Ford Shale Trend producing properties. We used cash in 2015 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 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.

 

 

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We have in place a Senior Credit Facility with a syndicate of U.S. and international lenders. As of December 31, 2015, we had a $75.0 million borrowing base with $27.0 million in outstanding borrowings and $11.8 million of cash. Our borrowing base was reduced to $47 million on January 6, 2016. Total lender commitments were reduced to $40.3 million on March 29, 2016. 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 not in compliance with existing covenants under the Senior Credit Facility at December 31, 2015. See “Senior Credit Facility” below for further information.

 

The following section discusses significant sources and uses of cash for the three-year period ending December 31, 2015. Forward-looking information related to our liquidity and capital resources are discussed above in “Key Developments”.

 

Capital Resources

 

Although we have taken many steps in 2015 to conserve capital and enhance our liquidity, we do not anticipate that our cash on hand, cash from operations and our available borrowing capacity under our Senior Credit Facility will be sufficient to meet our investing, financing, and working capital requirements in 2016. The sustained continuation of depressed commodity price levels will result in financial results that could violate a financial covenant despite the flexibility we have obtained under the revised debt covenants under the Senior Credit Facility. This could prevent us from accessing our borrowings available under the Senior Credit Facility.

 

The table below summarizes the sources of cash during 2015, 2014 and 2013:

 

 

At December 31, 2015, we had a working capital deficit of $9.5 million and no long-term debt.

Cash Flows

 

Year ended December 31, 2015 Compared to Year ended December 31, 2014

 

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 used in operating activities for 2015 totaled $17.0 million, down $138.7 million from net cash provided by operating in 2014. Operating cash flows before working capital changes decreased to $43.2 million in 2015 from $96.2 million in 2014 reflecting the absence of cash flows from natural gas properties sold in December 2014, lower commodity prices and the absence of cash flows from our Eagle Ford Shale Trend properties that we sold in September 2015. The change in working capital in 2015 reflects the use of $60.2 million in cash in the wind down of our drilling activity. Comparatively, working capital provided $25.5 million in cash in 2014, reflecting the timing of our payments.

 

Investing activities: Net cash used in investing activities was $4.9 million for the year ended December 31, 2015, compared to $268.4 million for the year ended December 31, 2014. While we booked capital expenditures of approximately $85.5 million in 2015, we paid out cash amounts totaling $118.4 million in 2015. The difference is attributed to $33.8 million accrued at December 31, 2014 and paid in 2015 and offset by $0.9 million in drilling and completion costs accrued at December 31, 2015. Capital expenditures in 2015 were offset by the receipt of $113.5 million in net proceeds, primarily from the sale of our Eagle Ford Shale Trend producing properties.

 

We conducted drilling and completion operations on 5 gross wells in 2015 compared to 30 gross wells in 2014. Of the $118.4 million cash spent in 2015, $106.4 million was for drilling and completion activities (of which $32.9 million related to 2014 wells); $4.3 million was for leasehold acquisition, $1.8 million for facilities and infrastructure and $5.9 million for capital workovers. 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.

 

 

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Financing activities: Net cash provided in financing activities for 2015 consisted of net proceeds from the issuance of 8.0% Second Lien Notes of $100.0 million and net proceeds from the sale of common stock of $47.5 million partially offset by net repayments of borrowings under the Senior Credit Facility of $94.0 million, preferred stock dividends of $14.9 million and debt issuance cost of $4.4 million. We had $27.0 million in borrowings outstanding under our Senior Credit Facility as of December 31, 2015.

 

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 2014, we paid out cash amounts totaling $322.3 million in 2014. The difference is attributable to $22.5 million accrued at December 31, 2013 and paid in 2014 and a $0.7 million non-cash adjustment 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.

 

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Debt consisted of the following balances as of the dates indicated (in thousands):

 

 

The following table summarizes the total interest expense (contractual interest expense, amortization of debt discount, accretion 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:

 

* - Not meaningful

Senior Credit Facility

Total lender commitments under the Senior Credit Facility are subject to a borrowing base limitation, which as of December 31, 2015 was $75 million. Our borrowing base was further reduced to $47 million on January 6, 2016. Total lender commitments were reduced to $40.3 million on March 29, 2016. 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, 2015, we had $27.0 million outstanding under the Senior Credit Facility.

 

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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. In March 2015, we closed on $100 million of 8.0% Second Lien Notes, which was used to pay down the amount drawn on our Senior Credit Facility.  Our borrowing base was further reduced to $150 million upon the funding of the 8.0% Second Lien Notes. On September 4, 2015, we closed on the sale of our Eagle Ford Shale Trend assets at which time the borrowing base was reduced to $105 million. In October 2015, we entered into the Fourteenth Amendment to the Senior Credit Facility (the “Fourteenth Amendment”) with an effective date of October 1, 2015. On the effective date, the Fourteenth Amendment reduced our borrowing base to $75 million in conjunction with the exchange of $158.2 million of our 2019 Notes for the issuance of $75.0 million of 8.875% Second Lien Notes. Our borrowing base was further reduced to $47 million on January 6, 2016. 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 of our assets are pledged as collateral to secure the Senior Credit Facility.

On October 1, 2015, the Company entered into the Fourteenth Amendment to the Senior Credit Facility. The Fourteenth Amendment includes the following key elements: (i) reduces the borrowing base to $75 million on October 1, 2015; (ii) permits the Company to refinance the 2019 Notes by issuing second lien or third lien debt (provided that the principal amount of third lien debt may not exceed $50 million); (iii) requires the Company to mortgage all of its oil and gas properties that constitute proved reserves; and (iv) authorizes the administrative agent under the Senior Credit Facility to enter into an amended and restated intercreditor agreement setting forth the priority of the liens securing the obligations under the Senior Credit Facility, the notes issued pursuant to the indentures of the Second Lien Notes and any third lien facility that the Company may enter into after the date hereof.

On November 3, 2015, the Company entered into the Fifteenth Amendment to the Senior Credit Facility (the “Fifteenth Amendment”) with an effective date of November 3, 2015. The Fifteenth Amendment includes the following key elements: (i) affirms the borrowing base as $75 million, which constitutes the October 1 redetermination; (ii) requires the Company to mortgage all of its owned real property in the Eagle Ford Shale Trend, the TMS and the Hayesville Shale Trend; and (iii) authorizes the administrative agent under the Senior Credit Facility to enter into an amended and restated intercreditor agreement setting forth the priority of the liens securing the obligations under the Senior Credit Facility, the notes issued pursuant to the indentures of the Second Lien Notes and any third lien facility that the Company may enter into after the effective date.

The Fifteenth Amendment also revised the Senior Credit Facility to include the following provisions and covenants: (i) no-hoarding provision of a maximum cash balance of $15 million at any time; (ii) no borrowed proceeds to make any payment on or redeem any capital or junior debt; (iii) restricts the ability to declare, pay or distribute dividends on our preferred capital stock consistent with the terms of the 8.0% Second Lien Notes and the 8.875% Second Lien Notes; and (iv) accelerated the next redetermination date to January 1, 2016.

The terms of the Senior Credit Facility 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 under the Fifteenth Amendment to the Senior Credit Facility, included:

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.

On March 29, 2016, the Company entered into the Sixteenth Amendment to the Senior Credit Facility (the “Sixteenth Amendment”). The Sixteenth Amendment includes the following key elements: (i) reduces total lender commitments to $40.3 million on March 29, 2016; (ii) the Company agrees not to request any borrowings, issue any new letters of credit or increase an existing letter of credit under the Senior Credit Facility before April 16, 2016; and (iii) requires that all letters of credit (except the letter of credit for

 

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the benefit of one specific vendor) expire at or prior to the earlier of (A) one year after the date of issuance or (B) five business days prior to February 24, 2017.

The report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern. Per the terms of our agreement, we are in default under our Senior Credit Facility. As a result of the default, we are unable to make further draws on the Senior Credit Facility unless the default is waived by the lenders under our Senior Credit Facility. We are currently in discussions with the lenders under our Senior Credit Facility regarding a waiver of this requirement. If we do not obtain a waiver of this requirement within 15 days, an event of default will exist under the Senior Credit Facility and the lenders under the Senior Credit Facility will be able to accelerate the repayment of debt under the Senior Credit Facility. Any acceleration of our debt obligations would result in a potential foreclosure on the collateral securing the Senior Credit Facility.

We elected to exercise our right to a grace period with respect to interest payments due on our 2019 Notes, our 8.0% Second Lien Notes and our 8.875% Second Lien Notes. The interest payments were due on March 15, 2016. Additionally, we have announced our intention to elect the right to a grace period with respect to interest payments due on, our 2029 Notes, our 2032 Notes and 2032 Exchange Notes. The interest payments are due on April 1, 2016. The grace periods permit us 30 days to make such interest payments before an event of default occurs under the indentures. Although, an event of default has not yet occurred, US GAAP requires us to classify all the related outstanding debt as a current liability. As a result, we are not in compliance with the Current Ratio covenant under the Senior Credit Facility as of December 31, 2015.

As stated previously, without the restructuring of our current obligations under our existing outstanding debt and preferred stock instruments, we anticipate that we will violate the First Lien Debt to EBITDAX financial covenant ratio under the Senior Credit Facility at the end of the third quarter of 2016. We could request a waiver of this covenant violation; however, there is no assurance a waiver will be granted. If a waiver is not granted, we would be in default under the Senior Credit Facility and the lenders under the Senior Credit Facility will be able to accelerate the repayment of debt under the Senior Credit Facility. Any acceleration of our debt obligations would result in a potential foreclosure on the collateral securing the Senior Credit Facility. The obligation to repay all such amounts could force us to seek bankruptcy protection. This factor, among other factors, raises substantial doubt about our ability to continue as a going concern.

8.0% Second Lien Senior Secured Notes due 2018

On March 12, 2015, we sold 100,000 units (the “Units”), each consisting of a $1,000 aggregate principal amount at maturity of our 8.0% Second Lien Notes and one warrant to purchase 48.84 shares of our $0.20 par value common stock. The 8.0% Second Lien Notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility. The Company received proceeds, before offering expenses payable by the Company, of $100 million from the sale of the Units. The proceeds from the issuance of the 8.0% Second Lien Notes were used to repay borrowings under the Senior Credit Facility and for general corporate purposes. The 8.0% Second Lien Notes are secured on a senior second-priority basis by liens on certain assets of the Company and its subsidiary that secures our Senior Credit Facility, which liens are subject to an inter-creditor agreement in favor of the lenders under the Senior Credit Facility. The 8.0% Second Lien Notes mature on March 15, 2018. If the aggregate principal amount outstanding on the 2032 Notes on August 1, 2017 is more than $25.0 million then the outstanding amount of the 8.0% Second Lien Notes shall be due on September 1, 2017.  Interest on the 8.0% Second Lien Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2015.  

We may redeem all or a portion of the 8.0% Second Lien Notes at redemption prices (expressed as percentages of principal amount) equal to (i) 106% for the twelve-month period beginning on March 15, 2016 and (ii) 100% on or after March 15, 2017, in each case plus accrued and unpaid interest to the redemption date.  Prior to March 15, 2016, we may redeem the 8.0% Second Lien Notes at a customary “make-whole” premium.

The indenture governing the 8.0% Second Lien 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 or our unsecured debt; (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 8.0% Second Lien 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 8.0% Second Lien Notes) has occurred and is continuing, many of these covenants will terminate.

The 8.0% Second Lien Notes and the warrants became separately transferable on June 4, 2015 when a registration statement related to the resale of the warrants was declared effective by the SEC. The warrants are exercisable upon payment of the exercise

 

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price of $4.664 or convertible on a cashless basis as set forth in the agreement governing the warrants. Any warrants not exercised by March 12, 2025 will expire.

In connection with the 8.0% Second Lien Notes, we entered into a registration rights agreement that provides holders of the 8.0% Second Lien Notes certain rights relating to registration of the 8.0% Second Lien Notes under the Securities Act of 1933, as amended (the “Securities Act”).  Pursuant to the registration rights agreement, the Company is obligated to file an exchange offer registration statement with the SEC with respect to an offer to exchange the 8.0% Second Lien Notes for substantially identical notes that are registered under the Securities Act. We agreed to commence the exchange offer promptly after the exchange offer registration statement was declared effective by the SEC and use our reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, we agreed to file a shelf registration statement with respect to the 8.0% Second Lien Notes. If the exchange offer was not completed on or before March 12, 2016, or the shelf registration statement, if required, was not declared effective within the time periods specified in the Registration Rights Agreement, we agreed to pay additional interest with respect to the 8.0% Second Lien Notes in an amount of 0.25% of the principal amount of the 8.0% Second Lien Notes per year for the first 90 days following such failure, increasing by 0.25% for each additional 90 days and not to exceed 1.00% of the principal amount per year, until the exchange offer is completed or the shelf registration statement is declared effective.  As of the date of this filing, neither an exchange offer nor shelf registration statement for the 8.0% Second Lien Notes had been filed with the SEC.

We separately accounted for the liability and equity components of our 8.0% Second Lien 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 8.0% Second Lien Notes using a discount rate of 32% on the date of issuance. We attributed $78.7 million of the 8.0% Second Lien Notes relative fair value to the debt component, which compared to the face value results in a debt discount of $15.4 million. Additionally, we recorded $15.4 million within additional paid-in capital representing the equity component of the 8.0% Second Lien Notes. We have also identified an embedded derivative associated with the 8.0% Second Lien Notes stemming from the length of time between the maturity date of March 15, 2018 and the put date of September 1, 2017. We valued the embedded derivative at $5.9 million using the discounted cash flow method on the date of issuance. The fair value of the embedded derivative was $5.1 million as of December 31, 2015 and is included in the carrying amount of the 8.0% Second Lien Notes. The embedded derivative feature is recorded at fair value each reporting period. The debt discount is being amortized using the effective interest rate method through September 1, 2017 along with the applicable debt issuance costs.  A debt discount of $11.0 million remains to be amortized on the 8.0% Second Lien Notes as of December 31, 2015.

8.875% Second Lien Senior Secured Notes due 2018

On October 1, 2015, we closed on a privately-negotiated exchange agreement under which we retired, in two tranches, $158.2 million in principal of our 2019 Notes for $75.0 million in principal of 8.875% Second Lien Notes. The first tranche exchanged $81.7 million of 2019 Notes for $36.8 million of 8.875% Second Lien Notes. The second tranche exchanged $76.5 million of 2019 Notes for $38.2 million of 8.875% Second Lien Notes which also included the issuance of 38,250 warrants. Each warrant is entitled to purchase approximately 156.9 shares of our $0.20 par value common stock for $1.00 per share. The 8.875% Second Lien Notes are secured on a senior second-priority basis by liens on certain assets of the Company and its subsidiary that secures our Senior Credit Facility, which liens are subject to an inter-creditor agreement in favor of the lenders under the Senior Credit Facility. The new 8.875% Second Lien Notes have a maturity date of March 15, 2018. If the aggregate principal amount outstanding on the 2032 Notes on August 1, 2017 is more than $25.0 million then the outstanding amount of the 8.875% Second Lien Notes shall be due on September 1, 2017. Interest on the 8.875% Second Lien Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning on March 15, 2016.

We may redeem all or a portion of the 8.875% Second Lien Notes at redemption prices (expressed as percentages of principal amount) equal to (i) 106% for the twelve-month period beginning on March 15, 2016 and (ii) 100% on or after March 15, 2017, in each case plus accrued and unpaid interest to the redemption date.  Prior to March 15, 2016, we may redeem the 8.875% Second Lien Notes at a customary “make-whole” premium.

The 8.875% Second Lien Notes contain a number of covenants including restrictions on (i) the incurrence of indebtedness similar to the restrictions in the Company’s 8.875% Senior Notes due 2019, (ii) the incurrence of liens including prior liens securing indebtedness in an amount in excess of the greater of $150 million and the borrowing base under Senior Credit Facility, equally ranking liens securing indebtedness in an amount (including the 8.875% Second Lien Notes) of more than $75 million, and junior liens securing indebtedness in an amount of more than $50 million, and (iii) restricted payments including the purchase or repayment of unsecured indebtedness prior to its scheduled maturity.

The indenture governing contains customary events of default. If an event of default, as defined, occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the 8.875% Second Lien Notes then outstanding may, and the

 

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trustee at the request of such holders shall, declare all unpaid principal and accrued and unpaid interest on the 8.875% Second Lien Notes to be due and payable immediately, by a notice in writing to the us. In the case of an event of default arising out of certain bankruptcy events, as defined, the principal and accrued and unpaid interest, on the New Notes will automatically become due and payable without any declaration or other act on the part of the trustee or any holders.

The 8.875% Second Lien Notes and the warrants will not be separately transferable until the earlier of (i) 60 days after the date on which the Warrants are originally issued or (ii) in the event of the occurrence of a change of control, as defined in the governing indenture. At such time, the warrants will become convertible on a cashless basis as set forth in the warrant agreement. Any warrants not exercised in ten years from the date of issuance will expire.

We accounted for this transaction as a troubled debt transaction pursuant to guidance provided by FASB Accounting Standards Codification (“ASC”) section 470-60 “Troubled Debt Restructurings by Debtors.” We have determined that the prospective undiscounted cash flows from the 8.875% Second Lien Notes through their maturity did not exceed the adjusted carrying amount of the retired 2019 Notes, consequently a gain of $62.6 million was recognized for this exchange. Accordingly, on the date of the exchange, a carrying amount of $91.4 million was recorded as a liability and we recorded $2.5 million in Additional paid in capital representing the fair value of the warrants issued.

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 unsecured 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.

As described above, on October 1, 2015, we closed a privately-negotiated exchange under which we retired, in two tranches, $158.2 million in aggregate original principal amount of our outstanding 2019 Notes in exchange for the issuance of $75.0 million in aggregate original principal amount of our 8.875% Second Lien Notes and 38,250 warrants. Following this exchange, approximately $116.8 million aggregate original principal amount of the 2019 Notes remain outstanding with terms unchanged.

We may redeem all or a portion of the 2019 Notes at redemption prices (expressed as percentages of principal amount) equal to approximately (i) 104% for the twelve-month period beginning on March 15, 2015; (ii) 102% for the twelve-month period beginning on March 15, 2016 and (iii) 100% on or after March 15, 2017, in each case 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.

5.0% 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. We exchanged $166.7 million of the 2029 Notes for the 2032 Notes in 2013.  On October 1, 2014, we repurchased $45.1 million of the 2029 Notes using 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).  As of September 30, 2015, $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 unsecured indebtedness. The 2029 Notes accrue interest at a rate of 5.0% annually, and interest is paid semi-annually in arrears on April 1 and October 1 of each year.

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: (i) 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;

 

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(ii) if the 2029 Notes have been called for redemption or (iii) 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 in subsequent periods. 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.

5.0% Convertible Senior Notes due 2032

As described above, we entered into separate, privately negotiated exchange agreements in 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.

On September 8, 2015, we closed a privately-negotiated exchange under which we retired $55.0 million in aggregate original principal amount of our outstanding 2032 Notes in exchange for our issuance of the 2032 Exchange Notes in an aggregate original principal amount of approximately $27.5 million. On October 14, 2015, we closed an additional privately-negotiated exchange under which we retired approximately $17.1 million in aggregate original principal amount of our outstanding 2032 Notes in exchange for our issuance of additional 2032 Exchange Notes in an aggregate original principal amount of approximately $8.5 million. As of December 31, 2015, $94.2 million in aggregate principal amount of the 2032 Notes remained outstanding with terms unchanged. See the description of the 2032 Exchange Notes below.

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 $2.9 million and $3.4 million of accretion in the years ended December 31, 2015 and 2014, respectively.

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 accounted 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 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 $2.0 million remains to be amortized on the 2032 Notes as of December 31, 2015.

5.0% Convertible Exchange Senior Notes due 2032

 

On September 8, 2015, we closed a privately-negotiated exchange under which we retired $55.0 million in principal amount of outstanding 2032 Notes in exchange for our issuance of approximately $27.5 million in aggregate original principal amount of 2032 Exchange Notes. On October 14, 2015, we closed an additional privately-negotiated exchange under which we retired approximately $17.1 million in aggregate original principal amount of our outstanding 2032 Notes in exchange for our issuance of additional 2032 Exchange Notes in an aggregate original principal amount of approximately $8.5 million. Many terms of the 2032 Exchange Notes remain the same as the 2032 Notes they replaced, including the 5.0% annual cash interest rate and the final maturity date of October 1, 2032.

 

 

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Investors may convert their 2032 Exchange 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) if the 2032 Exchange Notes have been called for redemption or the Company exercises its option to convert the 2032 Exchange Notes, or (2) upon the occurrence of one of specified corporate transactions. The conversion rate is 500.00 shares per $1,000 principal amount of the 2032 Exchange Notes (equal to an initial conversion price of $2.00 per share of common stock), subject to adjustment.

 

If the holders elect to convert the 2032 Exchange Notes on or before October 1, 2018, holders will receive a make-whole premium equal to (i) $100 per $1,000 face amount of the 2032 Exchange Notes if the conversion occurs prior to October 1, 2017 or (ii) $100 per $1,000 face amount of the 2032 Exchange Notes less an amount equal to 0.2778 multiplied by the number of days between September 30, 2017 and the conversion date, if the conversion occurs on or after October 1, 2017.

 

Like the 2032 Notes, the principal amount of the 2032 Exchange Notes will accrete at a rate of 2% per year from August 26, 2013, compounding on a semi-annual basis, until October 1, 2018. 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 Exchange Notes on each of October 1, 2018, October 1, 2022 and October 1, 2027, at a price equal to 100% of the accreted principal amount thereof, plus accrued and unpaid interest on the original principal amount thereof.  We have the right to redeem the 2032 Exchange Notes on or after October 1, 2017, at a price equal to 100% of the accreted principal amount thereof, plus accrued but unpaid interest on the original principal amount thereof. The 2032 Exchange Notes also provide us with the option to convert the 2032 Exchange Notes in whole or in part, prior to maturity, into the underlying common stock, provided the trading price of our common stock exceeds 125% of the then applicable conversion price for at least 20 trading days in any 30 trading day period. The initial conversion rate is 500 shares of common stock per $1,000 principal amount of 2032 Exchange Notes, subject to adjustment. Upon conversion, we must deliver, at our option, either (1) a number of shares of our common stock determined as set forth in the indenture related to the 2032 Exchange Notes, or (2) a combination of cash and shares of our common stock, if any.

 

We accounted for these transactions as troubled debt transactions pursuant to guidance provided by FASB Accounting Standards Codification (“ASC”) section 470-60 “Troubled Debt Restructurings by Debtors”. We have determined that the prospective undiscounted cash flows from the 2032 Exchange Notes through their maturity exceed the adjusted carrying amount of the retired 2032 Notes, consequently a gain on extinguishment of debt was not recognized for these exchanges. Accordingly, on the date of the September 8, 2015 exchange, a carrying amount of $45.2 million remained as a liability and we recorded $10.1 million to additional paid in capital representing the net fair value of the convert feature. On the date of the October 14, 2015 exchange, a carrying amount of $14.8 million remained as a liability and we recorded $2.5 million to additional paid in capital representing the net fair value of the convert feature. An annual discount rate of 1.3% and 1.4%, respectively, will be used to amortize the liability until maturity on October 1, 2032. From September 8, 2015 to December 31, 2015, holders converted an aggregate amount of $17.1 million of 2032 Exchange Notes into our common stock. As of December 31, 2015, $42.2 million aggregate principal amount of the 2032 Exchange Notes remained outstanding.

 

3.25% Convertible Senior Notes Due 2026

 

At December 31, 2015, $0.4 million of our 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:

5.375% Series B Cumulative Convertible Preferred Stock

 

During 2005 and 2006 we issued a total of 2,250,000 shares of our Series B Preferred Stock. Each share of the Series B Preferred Stock has a liquidation preference of $50 per share, aggregating to $112.5 million, and bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears. On December 18, 2015, holders of the Series B Preferred Stock exchanged 758,434 shares of Series B Preferred Stock for 910,112 depositary shares of our new Series E Preferred Stock in conjunction with a tender

 

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offer. Holders that participated in the Series E Preferred Stock exchange forfeited any claim to all dividends in arrears and any unpaid dividends through the settlement date of the exchange tender offer. As of December 31, 2015 there were $2.0 million of Series B Preferred Stock dividends in arrears. We are not in a position to declare or issue any dividends due to a lack of surplus as defined under Delaware state law.

 

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. On December 18, 2015, holders of the Series C Preferred Stock exchanged 1,274,932 depositary shares of Series C Preferred Stock for 1,274,932 depositary shares of our new Series E Preferred Stock in conjunction with a tender offer. Holders that participated in the Series E Preferred Stock exchange forfeited any claim to all dividends in arrears and any unpaid dividends through the settlement date of the exchange tender offer. As of December 31, 2015 there were $3.9 million of Series C Preferred Stock dividends in arrears. We are not in a position to declare or issue any dividends due to a lack of surplus as defined under Delaware state law.

 

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. On December 18, 2015, holders of the Series D Preferred Stock exchanged 1,463,759 depositary shares of Series D Preferred Stock for 1,463,759 depositary shares of our new Series E Preferred Stock in conjunction with a tender offer. Holders that participated in the Series E Preferred Stock exchange forfeited any claim to all dividends in arrears and any unpaid dividends through the settlement date of the exchange tender offer. As of December 31, 2015 there were $4.6 million of Series D Preferred Stock dividends in arrears. We are not in a position to declare or issue any dividends due to a lack of surplus as defined under Delaware state law.

 

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

 

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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.

 

10% Series E Cumulative Convertible Preferred Stock

 

In conjunction with a tender offer that settled on December 18, 2015 we issued 3,648,803 depositary shares of Series E Preferred Stock in exchange for 758,434 shares of Series B Preferred Stock, 1,274,932 depositary shares of Series C Preferred Stock and 1,463,759 depositary shares of Series D Preferred Stock.

 

The Series E Preferred Stock ranks senior to our common stock and on parity with our Series B Preferred Stock, our Series C 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 E 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.

 

The Series E Preferred Stock is convertible into shares of our $0.20 per share par value common stock at any time during the life of the security. The conversion rate will initially be 5.00 shares of common stock per depositary share of Series E Preferred Stock, which is equivalent to a conversion price of approximately $2.00 per share of common stock. Upon conversion of the Series E Preferred Stock, we may choose to deliver the conversion value to holders in cash, shares of our common stock, or a combination of cash and shares of our common stock.

 

Holders of shares of our Series E Preferred Stock are entitled to receive, when and if declared by our board of directors out of funds legally available for payment, cumulative dividends at the rate per annum of 10.00% per share on the liquidation preference thereof of $10.00 per share of our Series E Preferred Stock (equivalent to $1.00 per annum per share). Dividends on our Series E Preferred Stock are payable quarterly on March 15, June 15, September 15 and December 15 of each year, beginning on March 15, 2016, at such annual rate, and shall accumulate from the most recent date as to which dividends shall have been paid whether or not in any dividend period or periods there have been funds legally available for the payment of such dividends. Accumulations of dividends on shares of our Series E Preferred Stock will not bear interest. We are currently not in a position to declare or issue any dividends due to a lack of surplus as defined under Delaware state law.

 

Dividends on the Series E Preferred Stock may be paid in cash, by delivery of shares of common stock, or through any combination of cash and common stock. If we elect to make any such payment, or any portion thereof, in shares of common stock, such shares shall be valued for such purpose, in the case of any dividend payment, at 95% of the market value as determined on the second trading day immediately prior to the record date for such dividend; provided that in no event shall such shares be valued less than $0.70 per share for such purpose.

 

We may not redeem the Series E Preferred Stock prior to April 10, 2018. At any time or from time to time on or after April 10, 2018 we may, at our option, redeem the Series E Preferred Stock, in whole or in part, upon not less than 30 nor more than 60 days’ notice, out of funds legally available therefore, at a redemption price equal to the $10.00 liquidation preference per share of the Series E Preferred Stock plus an amount equal to accumulated and unpaid dividends (whether or not declared), if any.

 

On or after the date of issuance, we may, at our option, cause the Series E Preferred Stock to be automatically converted into that number of shares of common stock that are issuable at the then-prevailing conversion rate. We may exercise our option to automatically convert the Series E Preferred Stock only if the closing price of our common stock equals or exceeds 150% of the then prevailing conversion price of the Series E Preferred Stock for at least twenty trading days in a period of thirty consecutive trading days. In addition, if there are fewer than 50,000 shares of Series E Preferred Stock outstanding, we may, at any time, at our option, cause the Series E Preferred Stock to be automatically converted into that number of shares of common stock equal to $10.00 (the

 

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liquidation preference per share of Series E Preferred Stock) divided by the lesser of the then prevailing conversion price and the market value of our common stock for the five (5) trading day period ending on the second trading day immediately prior to the date we exercise our option to cause the Series E Preferred Stock to be automatically converted. We may choose to deliver the conversion value in connection with a conversion to investors in cash, shares of common stock, or a combination of cash and common stock.

 

For additional information on our debt and equity instruments, see Note 4—Debt and Note 7—Stockholders’ Equity in the Notes to Consolidated Financial Statements in “Item 8—Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

 

Future Commitments

 

The table below (in thousands) provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2015. In addition to the contractual obligations presented in the table below, our Consolidated Balance Sheet at December 31, 2015 reflects accrued interest on our bank debt of $6.6 million payable in the first half of 2016. For additional information see Note 4—Debt and Note 9—Commitments and Contingencies in the Notes to Consolidated Financial Statements in “Item 8—Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

 

 

Summary of Critical Accounting Policies and Estimates

 

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 “Item 8—Financial Statements and Supplementary Data” 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 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

 

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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, 2015 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 or their estimated fair value if an impairment has been identified. 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 “Item 8—Financial Statements and Supplementary Data” 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 overstated. We must evaluate our properties for potential impairment when certain indicators or circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows. 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, the availability of capital to develop proved undeveloped reserves 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.

 

 

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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 “Item 8— Financial Statements and Supplementary Data” 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 “Item 8—Financial Statements and Supplementary Data” 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.

 

 

 

 

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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—Description of Business and Accounting Policies, Note 8—Derivative Activities and Note 4—Debt in the Notes to Consolidated Financial Statements in “Item 8— Financial Statements and Supplementary Data” 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. Furthermore, additional non-cash write-downs of our oil and natural gas properties may be required if future commodity prices experience further sustained and significant declines. 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, 2015. At December 31, 2015, we had a de minimis liability derivative position related to natural gas 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 increased the derivative liability position, while a hypothetical 10% decrease in underlying commodity prices would have decreased the derivative liability. The aforementioned decrease and increase in the derivative liability position would be de minimis to our consolidated financial statements as of December 31, 2015. Furthermore, a gain or loss would be substantially offset by an increase or decrease, respectively, in the actual sales value of production covered by the derivative instruments.

 

Interest Rate Risk

 

As of December 31, 2015, we had $27.0 million outstanding variable-rate debt and $423.2 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, 2015, 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 natural gas production to a limited number of purchasers.

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

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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, 2015. The effectiveness of our internal control over financial reporting as of December 31, 2015 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report included on page 63.

Management of Goodrich Petroleum Corporation  

 

 

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

The Board of Directors and Stockholders of

Goodrich Petroleum Corporation

 

We have audited Goodrich Petroleum Corporation and subsidiary’s internal control over financial reporting as of December 31, 2015, 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, 2015, based on the COSO criteria.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2015 consolidated financial statements of Goodrich Petroleum Corporation and subsidiary and our report dated March 30, 2016 expressed an unqualified opinion thereon that included an explanatory paragraph regarding Goodrich Petroleum Corporation and subsidiary’s ability to continue as a going concern.

 

/s/ Ernst & Young LLP

 

Houston, Texas

March 30, 2016

 

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

The Board of Directors and Stockholders of

Goodrich Petroleum Corporation

 

We have audited the accompanying consolidated balance sheets of Goodrich Petroleum Corporation and subsidiary as of December 31, 2015 and 2014, and the related consolidated statements of operations, cash flows, and stockholders’ equity/(deficit), for each of the three years in the period ended December 31, 2015. 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, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has near term liquidity constraints and is not in compliance with their Current Ratio covenant that raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

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, 2015, 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 March 30, 2016 expressed an unqualified opinion thereon.

 

/s/ Ernst & Young LLP

 

Houston, Texas

March 30, 2016

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In Thousands)

  

 

See accompanying notes to consolidated financial statements.

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

 

 

See accompanying notes to consolidated financial statements.

 

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

 

 

See accompanying notes to consolidated financial statements.  

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT)

(In Thousands)

 

  

See accompanying notes to consolidated financial statements.  

 

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1—Description of Business, Management Plan 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 Trend (“TMS”), (ii) Northwest Louisiana and East Texas, which includes the Haynesville Shale, and (iii) South Texas, which includes the Eagle Ford Shale Trend.

The report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern As a result, we are in default of an affirmative covenant under our Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”). As a result of the default, we are unable to make further draws on the Senior Credit Facility unless the default is waived by the lenders under our Senior Credit Facility. We are currently in discussions with the lenders under our Senior Credit Facility regarding a waiver of this requirement. If we do not obtain a waiver of this requirement within 15 days, an event of default will exist under the Senior Credit Facility and the lenders under the Senior Credit Facility will be able to accelerate the repayment of debt under the Senior Credit Facility.

We elected to exercise our right to a grace period with respect to interest payments due on our 2019 Notes, our 8.0% Second Lien Notes and our 8.875% Second Lien Notes. The interest payments were due on March 15, 2016. Additionally, we have announced our intention to elect the right to a grace period with respect to interest payments due on, our 2029 Notes, our 2032 Notes and 2032 Exchange Notes. The interest payments are due on April 1, 2016. The grace periods permit us 30 days to make such interest payments before an event of default occurs under the indentures. Though, an event of default has not yet occurred, accounting principles generally accepted in the United States (“US GAAP”) requires us to classify all the related outstanding debt as a current liability. As a result, we are not in compliance with the Current Ratio covenant under the Senior Credit Facility as of December 31, 2015.

 

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 significant and sustained 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 taken the following steps in 2015 and 2016 to mitigate the effects of lower crude oil prices on our operations and conserve capital:

 

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Recapitalization Plan

In response to the decline of our operating cash flow, on January 26, 2016, the Company launched a comprehensive plan to reduce its cost structure and improve its operating results, cash flow from operations, liquidity and financial condition (the “Recapitalization Plan”). The Recapitalization Plan consists of the following transactions:

If successful, the Recapitalization Plan will have several positive effects on the Company’s capital structure and the holders of  our common stock, including: (i) the reduction in debt and preferred liquidation preference versus substantial dilution to the Company’s outstanding common stock expected to result from the Recapitalization Plan; (ii) the reduction of the Company’s fixed dividend obligations and the increase in the percentage of its capitalization that is common stock; (iii) the simplification of the Company’s capital structure and the elimination of the market overhang caused by the outstanding Preferred Stock and the liquidation preferences of the Preferred Stock; (iv) expected improvements in institutional investor interest in the Company’s common stock following the Recapitalization Plan due to an improved balance sheet and (v) the increased ability of the Company to address its near-term liquidity needs, including the material reduction of cash interest expense on the Company’s secured debt obligations and the increased likelihood of attracting new capital due to a significantly improved balance sheet.

The Recapitalization Plan is intended to facilitate a proposed recapitalization of the Company in an effort to simplify its capital structure, preserve liquidity and increase its ability to comply with its debt instruments during the current decline in the oil and gas industry. The Exchange Offers are conditioned, among other things, on (i) the Company’s common shareholders approving an amendment to the Company’s Restated Certificate of Incorporation increasing the number of authorized shares of common stock to 400 million (the “Authorized Share Amendment Proposal”) and (ii) the satisfaction of certain minimum participation thresholds according to the terms of each of the Exchange Offers. The Company will hold a special meeting of stockholders on March 31, 2016 to approve the Authorized Share Amendment Proposal.

Going Concern

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.

Given the downturn in oil and natural gas prices, we expect to continue to face liquidity constraints.  Our cash flows are negatively impacted by lower realized oil and natural gas sales prices. As of December 31, 2015 we no longer had any oil derivative

 

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contracts in place. Given the current oil futures pricing, we currently have limited hedging opportunities; as a result, we do not anticipate having in place any derivative positions with respect to our 2016 anticipated oil and condensate sales volumes and thus expect further deteriorating realized sale prices if oil prices do not improve.

The significant decline in oil and natural gas prices also increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market.  The prolonged period of depressed commodity prices has significantly impacted our estimated proved reserves as of December 31, 2015.  Future declines in commodity prices and estimated proved reserves could lead to further reductions of our borrowing base under the Senior Credit Facility. Such reductions could prevent us from borrowing additional amounts under the Senior Credit Facility or, if the borrowing base were to be reduced below the then-outstanding borrowings, could require us to repay the shortfall and could otherwise limit our ability to obtain alternative financing. In addition, if downward revisions of proved reserves occur in the future, we could have further increases in our DD&A rates and additional oil and natural gas property impairment charges. We are unable to predict the timing and amount of future reserve revisions, nor the impact such revisions may have on our future DD&A rates or oil and natural gas property impairments.

Without the restructuring of our current obligations under our existing outstanding debt and preferred stock instruments, we anticipate that we will violate the First Lien Debt to EBITDAX financial covenant ratio under the Senior Credit Facility at the end of the third quarter of 2016. We could request a waiver of this covenant violation; however, there is no assurance a waiver will be granted. If a waiver is not granted, we would be in default under the Senior Credit Facility and all amounts outstanding under the Senior Credit Facility would be immediately due and payable. The obligation to repay all such amounts could force us to seek bankruptcy protection.

Collectively, the factors discussed above raise substantial doubt about our ability to continue as a going concern. Furthermore, if we are unable to restructure our current obligations under our existing outstanding debt and preferred stock instruments, and address near-term liquidity needs, we may need to seek relief under the U.S. Bankruptcy Code. This relief may include: (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of the Company’s assets pursuant to section 363(b) of the U.S. Bankruptcy Code and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization (where votes for the plan may be solicited from certain classes of creditors prior to a bankruptcy filing) that the Company would seek to confirm (or “cram down”) despite any classes of creditors who reject or are deemed to have rejected such plan; or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.

 

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 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.

 

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.

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 December 31, 2015 our allowance for doubtful accounts was immaterial, while at December 31, 2014 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.

 

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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 had no capitalized exploratory well costs that were pending the determination of proved reserves as of December 31, 2015 and had $14.5 million as of December 31, 2014. During 2015 and 2014, all of the December 31, 2014 and December 31 2013 pending exploratory well costs were capitalized, respectively. During 2013 $4.4 million of the December 31, 2012 pending capitalized 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:

As of December 31, 2015 and 2014, 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.

 

 

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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 overstated or 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.

To determine if a field is impaired, we compare the carrying value of the field to the undiscounted future net cash flows by applying management’s estimates of proved reserves, future oil and natural gas prices, future production of oil and natural gas reserves and future operating costs over the economic life of the property. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and the availability of capital to develop proved undeveloped reserves. 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 field.

Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded in accumulated depletion, depreciation and amortization to reduce the carrying value of the field. Each part of this calculation is subject to a large degree of judgment, including the determination of the fields’ estimated reserves, future cash flows and fair value.

 

As of December 31, 2015, we had interests in oil and natural gas properties totaling $69.6 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”).

 

In the third and fourth quarters of 2015, the average NYMEX 5-year forward strip pricing for oil and natural gas had significantly decreased compared to year end 2014. The declines in commodity prices is an indication that the carrying amount of certain of our oil and natural gas properties may not be recoverable from future cash flows.  Our impairment analysis in the third quarter of 2015 resulted in the recording a $32.5 million impairment on certain of our natural gas properties, which reduced the impaired fields’ carrying value to an estimated fair value of $7.8 million at the end of the third quarter. During the fourth quarter of 2015, NYMEX forward 5-year strip oil prices continued to decline by an average of 16% and natural gas strip prices continued to decline by an average of 6%. The price declines in the fourth quarter of 2015 resulted in recording an additional impairment of $419.6 million on both our oil and natural gas properties. The $419.5 million impairment recognized in the fourth quarter of 2015 reduced the carrying value of the impaired fields to an estimated fair value of $63.4 million as of December 31, 2015. In the aggregate we recorded $452.0 million of impairments during 2015. For the year ended December 31, 2014 we recorded $ 331.9 million of oil and natural gas property 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. This obligation was relieved upon the sale of our Eagle Ford Shale Trend properties in September 2015, however we are obligated to pay the 2015 annual billing. As a result, the transportation obligation liability was reduced to $1.0 million as of December 31, 2015. The transportation obligation liability was $5.4 million as of December 31, 2014.

 

 

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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 was being amortized using the units-of-production method and the amortization expense was included in “Transportation and processing” on the Consolidated Statements of Operations. The related current and long-term liabilities were presented on the Consolidated Balance Sheets in “Accrued liabilities” and “Transportation obligation,” respectively.

 

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.

 

The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.

 

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, 2015 and 2014, 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 Series B Preferred Stock, Series E Preferred Stock, 2026 Notes, 2029 Notes, 2032 Notes and the 2032 Exchange 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.

 

 

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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, 2015, 2014 and 2013 are as follows:

 

 

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 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. On March 12, 2015, we issued and sold $100 million aggregate principal amount of our 8.0% Second Lien Notes and upon issuance our subsidiary became the guarantor of the 8.0% Second Lien Notes under the governing indenture. On September 8, 2015 and October 14, 2015, we issued $27.5 million and $8.5 million, respectively, aggregate principal amount of our 2032 Exchange Notes and, upon issuance, our subsidiary became the guarantor of the 2032 Exchange Notes under the governing indenture. On October 1, 2015, we issued and sold $75 million aggregate principal amount of our 8.875% Second Lien Notes and upon issuance our subsidiary became the guarantor of the 8.875% Second Lien Notes under the governing indenture. The 2019 Notes, 2029 Notes, 2026 Notes, 2032 Notes, 8.0% Second Lien Notes, 2032 Exchange Notes, and 8.875 Second Lien 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, 2032 Notes, 8.0% Second Lien Notes, 2032 Exchange Notes, and 8.875 Second Lien 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 Exchange Notes, 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 Exchange Notes, 2032 Notes, 2029 Notes or 2026 Notes in accordance with their respective indentures.

 

 

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Guarantees of the 8.0% Second Lien Notes and 8.875% Second Lien Notes (the “Second Lien Notes ) will be released under certain circumstances, including in the event the 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 8.0% Second Lien 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, provided no Event of Default (as defined in the indenture governing the Second Lien 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 Second Lien Notes in accordance with the indenture.

 

New Accounting Pronouncements

 

In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, which seeks to simplify the presentation of deferred income taxes. The amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. For public business entities, the amendments in this update are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The adoption of this guidance is not expected to have a material impact on our consolidated financial statements.

In September 2015, the FASB issued ASU 2015-16, which requires an acquirer in a business combination to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The acquirer is required to adjust its financial statements for the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts calculated as if the accounting had been completed at the acquisition date. This ASU is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, to simplify the accounting for measurement-period adjustments for an acquirer in a business combination. We are currently evaluating the provisions of ASU 2015-16 and assessing the impact, if any, it may have on our financial position and results of operations.

In August 2015, the FASB issued ASU 2015-15. The ASU incorporates the SEC staff's announcement that clarifies the exclusion of line-of-credit arrangements from the scope of ASU 2015-03. Therefore, debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the time of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We are currently evaluating the provisions of this ASU and assessing the impact it may have on our consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest, which seeks to simplify presentation of debt issuance costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. Entities should apply the amendments in this ASU on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. For public entities, this ASU is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. We will adopt the provisions of this ASU in 2016 and it will not have a significant impact on our consolidated financial statements.

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, 2017, 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.

 

 

 

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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 2015, a maximum of 7.0 million shares are authorized for issuance as awards of restricted stock and stock options. We had 3.1 million shares of granted but unvested restricted stock and zero shares were available for future grants as of December 31, 2015.

 

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):

 

 

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.

Option activity under our stock option plans as of December 31, 2015, and changes during the year ended December 31, 2015 were as follows:

 

 

 

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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 2015 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, 2015. 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, 2015, 2014 and 2013 was less than $0.3 million. The outstanding options had no intrinsic value as of December 31, 2015.

 

 

 

As of December 31, 2015, all compensation cost related to the stock options has been recognized in earnings. No stock options were granted in 2015, 2014 or 2013.

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, 2015, 2014 and 2013 were as follows:

 

 

Restricted stock activity under our plan for the year ended December 31, 2015, and changes during the year then ended were as follows:

 

 

As of December 31, 2015, total unrecognized compensation cost related to restricted stock is as follows:

 

 

 

 

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NOTE 3—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the periods ending December 31, 2015 and 2014 is as follows (in thousands):

 

 

 

 

NOTE 4—Debt

Debt consisted of the following balances as of the dates indicated (in thousands):

 

 

 

 

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The following table summarizes the total interest expense for the years ended (contractual interest expense, amortization of debt discount, accretion 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:

 

* - Not meaningful

 

Deferred financing costs are amortized using the straight-line method through the contractual maturity dates for the Senior Credit Facility and 2019 Notes, through the first put date of September 1, 2017 for the 8.0% Second Lien 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 subject to a borrowing base limitation, which as of December 31, 2015 was $75 million. Our borrowing base was further reduced to $47 million on January 6, 2016. Total lender commitments were reduced to $40.3 million on March 29, 2016. 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, 2015, we had $27.0 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. In March 2015, we closed on $100 million of 8.0% Second Lien Notes, which was used to pay down the amount drawn on our Senior Credit Facility.  Our borrowing base was further reduced to $150 million upon the funding of the 8.0% Second Lien Notes. On September 4, 2015, we closed on the sale of our Eagle Ford Shale Trend assets at which time the borrowing base was reduced to $105 million. In October 2015, we entered into the Fourteenth Amendment to the Senior Credit Facility (the “Fourteenth Amendment”) with an effective date of October 1, 2015. On the effective date, the Fourteenth Amendment reduced our borrowing base to $75 million in conjunction with the exchange of $158.2 million of our 2019 Notes for the issuance of $75.0 million of 8.875% Second Lien Notes due 2018. Our borrowing base was reduced to $47 million on January 6, 2016. 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 of our assets are pledged as collateral to secure the Senior Credit Facility.

On October 1, 2015, the Company entered into the Fourteenth Amendment to the Senior Credit Facility. The Fourteenth Amendment includes the following key elements: (i) reduces the borrowing base to $75 million on October 1, 2015; (ii) permits the Company to refinance the 2019 Notes by issuing second lien or third lien debt (provided that the principal amount of third lien debt may not exceed $50 million); (iii) requires the Company to mortgage all of its oil and gas properties that constitute proved reserves; and (iv) authorizes the administrative agent under the Senior Credit Facility to enter into an amended and restated intercreditor agreement setting forth the priority of the liens securing the obligations under the Senior Credit Facility, the notes issued pursuant to the indentures of the Second Lien Notes and any third lien facility that the Company may enter into after the date hereof.

On November 3, 2015, the Company entered into the Fifteenth Amendment to the Senior Credit Facility (the “Fifteenth Amendment”) with an effective date of November 3, 2015. The Fifteenth Amendment includes the following key elements: (i) affirms the borrowing base as $75 million, which constitutes the October 1 redetermination; (ii) requires the Company to mortgage all of its owned real property in the Eagle Ford Shale Trend, the Tuscaloosa Marine Shale Trend and the Hayesville Shale Trend; and (iii) authorizes the administrative agent under the Senior Credit Facility to enter into an amended and restated intercreditor agreement

 

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setting forth the priority of the liens securing the obligations under the Senior Credit Facility, the notes issued pursuant to the indentures of the Second Lien Notes and any third lien facility that the Company may enter into after the effective date.

The Fifteenth Amendment also revised the Senior Credit Facility to include the following provisions and covenants: (i) no-hoarding provision of a maximum cash balance of $15 million at any time; (ii) no borrowed proceeds to make any payment on or redeem any capital or junior debt; (iii) restricts the ability to declare, pay or distribute dividends on our preferred capital stock consistent with the terms of the 8.0% Second Lien Notes and the 8.875% Second Lien Notes; and (iv) accelerated the next redetermination date to January 1, 2016

The terms of the Senior Credit Facility 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 under the Fifteenth Amendment to the Senior Credit Facility, included:

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.

On March 29, 2016, the Company entered into the Sixteenth Amendment to the Senior Credit Facility (the “Sixteenth Amendment”). The Sixteenth Amendment includes the following key elements: (i) reduces total lender commitments to $40.3 million on March 29, 2016; (ii) the Company agrees not to request any borrowings, issue any new letters of credit or increase an existing letter of credit under the Senior Credit Facility before April 16, 2016; and (iii) requires that all letters of credit (except the letter of credit for the benefit of one specific vendor) expire at or prior to the earlier of (A) one year after the date of issuance or (B) five business days prior to February 24, 2017.

The report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern. Per the terms of our agreement, we are in default under our Senior Credit Facility. As a result of the default, we are unable to make further draws on the Senior Credit Facility unless the default is waived by the lenders under our Senior Credit Facility. We are currently in discussions with the lenders under our Senior Credit Facility regarding a waiver of this requirement. If we do not obtain a waiver of this requirement within 15 days, an event of default will exist under the Senior Credit Facility and the lenders under the Senior Credit Facility will be able to accelerate the repayment of debt under the Senior Credit Facility. Any acceleration of our debt obligations would result in a foreclosure on the collateral securing the Senior Credit Facility.

We elected to exercise our right to a grace period with respect to the interest payments that were due on March 15, 2016 on our 2019 Notes, 8.0% Second Lien Notes and 8.875% Second Lien Notes. Additionally, we have announced our intention to elect the right to a grace period with respect to interest payments due on, our 2029 Notes, our 2032 Notes and 2032 Exchange Notes. The interest payments are due on April 1, 2016. The grace periods permit us 30 days to make such interest payments before an event of default occurs under the indentures. Although, an event of default has not yet occurred, US GAAP requires us to classify all the related outstanding debt as a current liability. As a result, we are not in compliance with the Current Ratio covenant under the Senior Credit Facility as of December 31, 2015.

As stated previously, without the restructuring of our current obligations under our existing outstanding debt and preferred stock instruments, we anticipate that we will violate the First Lien Debt to EBITDAX financial covenant ratio under the Senior Credit Facility at the end of the third quarter of 2016. We could request a waiver of this covenant violation; however, there is no assurance a waiver will be granted. If a waiver is not granted, we would be in default under the Senior Credit Facility and the lenders will be able to accelerate the repayment of debt under the Senior Credit Facility. Any acceleration of our debt obligations would result in a potential foreclosure on the collateral securing the Senior Credit Facility. The obligation to repay all such amounts could force us to seek bankruptcy protection. This factor, among other factors, raises substantial doubt about our ability to continue as a going concern.

 

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8.0% Second Lien Senior Secured Notes due 2018

On March 12, 2015, we sold 100,000 units (the “Units”), each consisting of a $1,000 aggregate principal amount at maturity of our 8.0% Second Lien Senior Secured Notes due 2018 (the “8.0% Second Lien Notes”) and one warrant to purchase 48.84 shares of our $0.20 par value common stock. The 8.0% Second Lien Notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility. The Company received proceeds, before offering expenses payable by the Company, of $100 million from the sale of the Units. The proceeds from the issuance of the 8.0% Second Lien Notes were used to repay borrowings under the Senior Credit Facility and for general corporate purposes. The 8.0% Second Lien Notes are secured on a senior second-priority basis by liens on certain assets of the Company and its subsidiary that secures our Senior Credit Facility, which liens are subject to an inter-creditor agreement in favor of the lenders under the Senior Credit Facility. The 8.0% Second Lien Notes mature on March 15, 2018. If the aggregate principal amount outstanding on the 2032 Notes on August 1, 2017 is more than $25.0 million then the outstanding amount of the 8.0% Second Lien Notes shall be due on September 1, 2017.  Interest on the 8.0% Second Lien Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2015.  

We may redeem all or a portion of the 8.0% Second Lien Notes at redemption prices (expressed as percentages of principal amount) equal to (i) 106% for the twelve-month period beginning on March 15, 2016 and (ii) 100% on or after March 15, 2017, in each case plus accrued and unpaid interest to the redemption date.  Prior to March 15, 2016, we may redeem the 8.0% Second Lien Notes at a customary “make-whole” premium.

The indenture governing the 8.0% Second Lien 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 or our unsecured debt; (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 8.0% Second Lien 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 8.0% Second Lien Notes) has occurred and is continuing, many of these covenants will terminate.

The 8.0% Second Lien Notes and the warrants became separately transferable on June 4, 2015 when a registration statement related to the resale of the warrants was declared effective by the SEC. The warrants are exercisable upon payment of the exercise price of $4.664 or convertible on a cashless basis as set forth in the agreement governing the warrants. Any warrants not exercised by March 12, 2025 will expire.

In connection with the 8.0% Second Lien Notes, we entered into a registration rights agreement that provides holders of the 8.0% Second Lien Notes certain rights relating to registration of the 8.0% Second Lien Notes under the Securities Act of 1933, as amended (the “Securities Act”).  Pursuant to the registration rights agreement, the Company is obligated to file an exchange offer registration statement with the SEC with respect to an offer to exchange the 8.0% Second Lien Notes for substantially identical notes that are registered under the Securities Act. We agreed to commence the exchange offer promptly after the exchange offer registration statement was declared effective by the SEC and use our reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, we agreed to file a shelf registration statement with respect to the 8.0% Second Lien Notes. If the exchange offer was not completed on or before March 12, 2016, or the shelf registration statement, if required, was not declared effective within the time periods specified in the Registration Rights Agreement, we agreed to pay additional interest with respect to the 8.0% Second Lien Notes in an amount of 0.25% of the principal amount of the 8.0% Second Lien Notes per year for the first 90 days following such failure, increasing by 0.25% for each additional 90 days and not to exceed 1.00% of the principal amount per year, until the exchange offer is completed or the shelf registration statement is declared effective.  As of the date of this filing, neither an exchange offer nor shelf registration statement for the 8.0% Second Lien Notes had been filed with the SEC.

We separately accounted for the liability and equity components of our 8.0% Second Lien 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 8.0% Second Lien Notes using a discount rate of 32% on the date of issuance. We attributed $78.7 million of the 8.0% Second Lien Notes relative fair value to the debt component, which compared to the face value results in a debt discount of $15.4 million. Additionally, we recorded $15.4 million within additional paid-in capital representing the equity component of the 8.0% Second Lien Notes. We have also identified an embedded derivative associated with the 8.0% Second Lien Notes stemming from the length of time between the maturity date of March 15, 2018 and the put date of September 1, 2017. We valued the embedded derivative at $5.9 million using the discounted cash flow method on the date of issuance. The fair value of the embedded derivative was $5.1 million as of December 31, 2015 and is included in the carrying amount of the 8.0% Second Lien Notes. The embedded derivative feature is recorded at fair value each reporting period. The debt discount is being amortized using the effective interest rate method through September 1, 2017

 

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along with the applicable debt issuance costs.  A debt discount of $11.0 million remains to be amortized on the 8.0% Second Lien Notes as of December 31, 2015.

8.875% Second Lien Senior Secured Notes due 2018

On October 1, 2015, we closed on a privately-negotiated exchange agreement under which we retired, in two tranches, $158.2 million in principal of our 8.875% Senior Notes due 2019 (the “2019 Notes”) for $75.0 million in principal of 8.875% Second Lien Notes due 2018 (the “8.875% Second Lien Notes”). The first tranche exchanged $81.7 million of 2019 Notes for $36.8 million of 8.875% Second Lien Notes. The second tranche exchanged $76.5 million of 2019 Notes for $38.2 million of 8.875% Second Lien Notes which also included the issuance of 38,250 warrants. Each warrant is entitled to purchase approximately 156.9 shares of our $0.20 par value common stock for $1.00 per share. The 8.875% Second Lien Notes are secured on a senior second-priority basis by liens on certain assets of the Company and its subsidiary that secures our Senior Credit Facility, which liens are subject to an inter-creditor agreement in favor of the lenders under the Senior Credit Facility. The new 8.875% Second Lien Notes have a maturity date of March 15, 2018. If the aggregate principal amount outstanding on the 2032 Notes on August 1, 2017 is more than $25.0 million then the outstanding amount of the 8.875% Second Lien Notes shall be due on September 1, 2017. Interest on the 8.875% Second Lien Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning on March 15, 2016.

We may redeem all or a portion of the 8.875% Second Lien Notes at redemption prices (expressed as percentages of principal amount) equal to (i) 106% for the twelve-month period beginning on March 15, 2016 and (ii) 100% on or after March 15, 2017, in each case plus accrued and unpaid interest to the redemption date.  Prior to March 15, 2016, we may redeem the 8.875% Second Lien Notes at a customary “make-whole” premium.

The 8.875% Second Lien Notes contain a number of covenants including restrictions on (i) the incurrence of indebtedness similar to the restrictions in the Company’s 8.875% Senior Notes due 2019, (ii) the incurrence of liens including prior liens securing indebtedness in an amount in excess of the greater of $150 million and the borrowing base under Senior Credit Facility, equally ranking liens securing indebtedness in an amount (including the 8.875% Second Lien Notes) of more than $75 million, and junior liens securing indebtedness in an amount of more than $50 million, and (iii) restricted payments including the purchase or repayment of unsecured indebtedness prior to its scheduled maturity.

The indenture governing contains customary events of default. If an event of default, as defined, occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the 8.875% Second Lien Notes then outstanding may, and the trustee at the request of such holders shall, declare all unpaid principal and accrued and unpaid interest on the 8.875% Second Lien Notes to be due and payable immediately, by a notice in writing to the us. In the case of an event of default arising out of certain bankruptcy events, as defined, the principal and accrued and unpaid interest, on the New Notes will automatically become due and payable without any declaration or other act on the part of the trustee or any holders.

The 8.875% Second Lien Notes and the warrants will not be separately transferable until the earlier of (i) 60 days after the date on which the Warrants are originally issued or (ii) in the event of the occurrence of a change of control, as defined in the governing indenture. At such time, the warrants will become convertible on a cashless basis as set forth in the warrant agreement. Any warrants not exercised in ten years from the date of issuance will expire.

We accounted for this transaction as a troubled debt transaction pursuant to guidance provided by FASB Accounting Standards Codification (“ASC”) section 470-60 “Troubled Debt Restructurings by Debtors.” We have determined that the prospective undiscounted cash flows from the 8.875% Second Lien Notes through their maturity did not exceed the adjusted carrying amount of the retired 2019 Notes, consequently a gain of $62.6 million was recognized for this exchange. Accordingly, on the date of the exchange, a carrying amount of $91.4 million was recorded as a liability and we recorded $2.5 million in Additional paid in capital representing the fair value of the warrants issued. On a basic and diluted loss per share basis the $62.6 million gain was $1.11 per share for the year ended December 31, 2015.

 

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.

As described above, on October 1, 2015, we closed a privately-negotiated exchange under which we retired, in two tranches, $158.2 million in aggregate original principal amount of our outstanding 2019 Notes in exchange for the issuance of $75.0 million in

 

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aggregate original principal amount of our 8.875% Second Lien Notes and 38,250 warrants. Following this exchange, approximately $116.8 million aggregate original principal amount of the 2019 Notes remain outstanding with terms unchanged.

We may redeem all or a portion of the 2019 Notes at redemption prices (expressed as percentages of principal amount) equal to approximately (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.

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. We exchanged $166.7 million of the 2029 Notes for the 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. As of December 31, 2015, $6.7 million in aggregate principal amount of the 2029 Notes remain outstanding. 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). As of December 31, 2015, $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 5.0% annually, and interest is paid semi-annually in arrears on April 1 and October 1 of each year.

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: (i) 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; (ii) if the 2029 Notes have been called for redemption or (iii) 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, 2015. 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.

On September 8, 2015, we closed a privately-negotiated exchange under which we retired $55.0 million in aggregate original principal amount of our outstanding 2032 Notes in exchange for our issuance of the 2032 Exchange Notes in an aggregate original principal amount of approximately $27.5 million. On October 14, 2015, we closed an additional privately-negotiated exchange under which we retired approximately $17.1 million in aggregate original principal amount of our outstanding 2032 Notes in exchange for our issuance of additional 2032 Exchange Notes in an aggregate original principal amount of approximately $8.5 million. As of December 31, 2015, $94.2 million in aggregate original principal amount of the 2032 Notes remained outstanding with terms unchanged. See the description of the 2032 Exchange Notes below.

 

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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 $3.0 million of accretion during 2015.

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 $2.0 million remains to be amortized on the 2032 Notes as of December 31, 2015.

5.0% Convertible Exchange Senior Notes due 2032

 

On September 8, 2015, we closed a privately-negotiated exchange under which we retired $55.0 million in principal amount of outstanding 2032 Notes in exchange for our issuance of approximately $27.5 million in aggregate original principal amount of 2032 Exchange Notes. On October 14, 2015, we closed an additional privately-negotiated exchange under which we retired approximately $17.1 million in aggregate original principal amount of our outstanding 2032 Notes in exchange for our issuance of additional 2032 Exchange Notes in an aggregate original principal amount of approximately $8.5 million. Many terms of the 2032 Exchange Notes remain the same as the 2032 Notes they replaced, including the 5.0% annual cash interest rate and the final maturity date of October 1, 2032.

 

Investors may convert their 2032 Exchange 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) if the 2032 Exchange Notes have been called for redemption or the Company exercises its option to convert the 2032 Exchange Notes, or (2) upon the occurrence of one of specified corporate transactions. The conversion rate is 500.00 shares per $1,000 principal amount of the 2032 Exchange Notes (equal to an initial conversion price of $2.00 per share of common stock), subject to adjustment.

 

If the holders elect to convert the 2032 Exchange Notes on or before October 1, 2018, holders will receive a make-whole premium equal to (i) $100 per $1,000 face amount of the 2032 Exchange Notes if the conversion occurs prior to October 1, 2017 or (ii) $100 per $1,000 face amount of the 2032 Exchange Notes less an amount equal to 0.2778 multiplied by the number of days between September 30, 2017 and the conversion date, if the conversion occurs on or after October 1, 2017.

 

Like the 2032 Notes, the principal amount of the 2032 Exchange Notes will accrete at a rate of 2% per year from August 26, 2013, compounding on a semi-annual basis, until October 1, 2018. 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 Exchange Notes on each of October 1, 2018, October 1, 2022 and October 1, 2027, at a price equal to 100% of the accreted principal amount thereof, plus accrued and unpaid interest on the original principal amount thereof.  We have the right to redeem the 2032 Exchange Notes on or after October 1, 2017, at a price equal to 100% of the accreted principal amount thereof, plus accrued but unpaid interest on the original principal amount thereof. The 2032 Exchange Notes also provide us with the option to convert the 2032 Exchange Notes in whole or in part, prior to maturity, into the underlying common stock, provided the trading price of our common stock exceeds 125% of the then applicable conversion price for at least 20 trading days in any 30 trading day period. The initial conversion rate is 500 shares of common stock per $1,000 principal amount of 2032 Exchange Notes, subject to adjustment. Upon conversion, we must deliver, at our option, either (1) a number of shares of our common stock determined as set forth in the indenture related to the 2032 Exchange Notes, or (2) a combination of cash and shares of our common stock, if any.

 

 

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We accounted for these transactions as troubled debt transactions pursuant to guidance provided by FASB Accounting Standards Codification (“ASC”) section 470-60 “Troubled Debt Restructurings by Debtors.” We have determined that the prospective undiscounted cash flows from the 2032 Exchange Notes through their maturity exceed the adjusted carrying amount of the retired 2032 Notes, consequently a gain on extinguishment of debt was not recognized for these exchanges. Accordingly, on the date of the September 8, 2015 exchange, a carrying amount of $45.2 million remained as a liability and we recorded $10.1 million to additional paid in capital representing the net fair value of the convert feature. On the date of the October 14, 2015 exchange, a carrying amount of $14.8 million remained as a liability and we recorded $2.5 million to additional paid in capital representing the net fair value of the convert feature. An annual discount rate of 1.3% and 1.4%, respectively, will be used to amortize the liability until maturity on October 1, 2032. From September 8, 2015 to December 31, 2015, holders converted an aggregate amount of $17.1 million of 2032 Exchange Notes into our common stock. As of December 31, 2015, $42.6 million aggregate principal amount of the 2032 Exchange Notes remained outstanding.

3.25% Convertible Senior Notes Due 2026

At December 31, 2015, $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:

 

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, 2015, 2014 and 2013. Included in Net loss applicable to common stock for the year ended December 31, 2015 is $10.5 million of preferred stock dividends in arrears as a result of all cash dividends being suspended since the third quarter of 2015 to conserve capital. The preferred stock dividend in arrears amount is included in the 2015 Net loss applicable to common stock calculation for period-to-period comparison purposes only. The following table sets forth information related to the computations of basic and diluted loss per share.

 

 

 

 

 

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NOTE 6—Income Taxes

 

We did not recognize any current or deferred income tax benefits or expense in 2015, 2014 or 2013.

 

The following is a reconciliation of the U.S. statutory income tax rate at 35% to our loss before income taxes (in thousands):

 

 

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):

 

 

 

The valuation allowance for deferred tax assets increased by $162.0 million in 2015. 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 2015 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 $162.0 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”)

 

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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, 2015, we have federal NOL carry-forwards of approximately $824.6 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, 2015. 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 2006.

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, 2016.

 

 

NOTE 7—Stockholders’ Equity

5.375% Series B Cumulative Convertible Preferred Stock

 

During 2005 and 2006 we issued a total of 2,250,000 shares of our Series B Preferred Stock. 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. On December 18, 2015, holders of the Series B Preferred Stock exchanged 758,434 shares of Series B Preferred Stock for 910,112 depositary shares of our new Series E Preferred Stock in conjunction with a tender offer. Holders that participated in the Series E Preferred Stock exchange forfeited any claim to all dividends in arrears and any unpaid dividends through the settlement date of the exchange tender offer. We suspended payment of dividends in the third quarter of 2015 consequently, as of December 31, 2015 there were $2.0 million of Series B Preferred Stock dividends in arrears.

 

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:

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

 

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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 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. On December 18, 2015, holders of the Series C Preferred Stock exchanged 1,274,932 depositary shares of Series C Preferred Stock for 1,274,932 depositary shares of our new Series E Preferred Stock in conjunction with a tender offer. Holders that participated in the Series E Preferred Stock exchange forfeited any claim to all dividends in arrears and any unpaid dividends through the settlement date of the exchange tender offer. As of December 31, 2015 there were $3.9 million of Series C Preferred Stock dividends in arrears.

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 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 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. On December 18, 2015, holders of the Series D Preferred Stock exchanged 1,463,759 depositary shares of Series D Preferred Stock for 1,463,759 depositary shares of our new Series E Preferred Stock in conjunction with a tender offer. Holders that participated in the Series E Preferred Stock exchange forfeited any claim to all dividends in arrears and any unpaid dividends through the settlement date of the exchange tender offer. As of December 31, 2015 there were $4.6 million of Series D Preferred Stock dividends in arrears.

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.

 

 

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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.

 

10% Series E Cumulative Convertible Preferred Stock

In conjunction with a tender offer that settled on December 18, 2015 we issued 3,648,803 depositary shares of Series E Preferred Stock in exchange for 758,434 shares of Series B Preferred Stock, 1,274,932 depositary shares of Series C Preferred Stock and 1,463,759 depositary shares of Series D Preferred Stock.

 

The Series E Preferred Stock ranks senior to our common stock and on parity with our Series B Preferred Stock, our Series C 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 E 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.

 

The Series E Preferred Stock is convertible into shares of our $0.20 per share par value common stock at any time during the life of the security. The conversion rate will initially be 5.00 shares of common stock per depositary share of Series E Preferred Stock, which is equivalent to a conversion price of approximately $2.00 per share of common stock. Upon conversion of the Series E Preferred Stock, we may choose to deliver the conversion value to holders in cash, shares of our common stock, or a combination of cash and shares of our common stock.

 

Holders of shares of our Series E Preferred Stock are entitled to receive, when and if declared by our board of directors out of funds legally available for payment, cumulative dividends at the rate per annum of 10.00% per share on the liquidation preference thereof of $10.00 per share of our Series E Preferred Stock (equivalent to $1.00 per annum per share). Dividends on our Series E Preferred Stock are payable quarterly on March 15, June 15, September 15 and December 15 of each year, beginning on March 15, 2016, at such annual rate, and shall accumulate from the most recent date as to which dividends shall have been paid whether or not in any dividend period or periods there have been funds legally available for the payment of such dividends. Accumulations of dividends on shares of our Series E Preferred Stock will not bear interest.

 

Dividends on the Series E Preferred Stock may be paid in cash, by delivery of shares of common stock, or through any combination of cash and common stock. If we elect to make any such payment, or any portion thereof, in shares of common stock, such shares shall be valued for such purpose, in the case of any dividend payment, at 95% of the market value as determined on the second trading day immediately prior to the record date for such dividend; provided that in no event shall such shares be valued less than $0.70 per share for such purpose.

 

We may not redeem the Series E Preferred Stock prior to April 10, 2018. At any time or from time to time on or after April 10, 2018 we may, at our option, redeem the Series E Preferred Stock, in whole or in part, upon not less than 30 nor more than 60 days notice, out of funds legally available therefore, at a redemption price equal to the $10.00 liquidation preference per share of the Series E Preferred Stock plus an amount equal to accumulated and unpaid dividends (whether or not declared), if any.

 

On or after the date of issuance, we may, at our option, cause the Series E Preferred Stock to be automatically converted into that number of shares of common stock that are issuable at the then-prevailing conversion rate. We may exercise our option to automatically convert the Series E Preferred Stock only if the closing price of our common stock equals or exceeds 150% of the then prevailing conversion price of the Series E Preferred Stock for at least twenty trading days in a period of thirty consecutive trading days. In addition, if there are fewer than 50,000 shares of Series E Preferred Stock outstanding, we may, at any time, at our option, cause the Series E Preferred Stock to be automatically converted into that number of shares of common stock equal to $10.00 (the liquidation preference per share of Series E Preferred Stock) divided by the lesser of the then prevailing conversion price and the market value of our common stock for the five (5) trading day period ending on the second trading day immediately prior to the date we exercise our option to cause the Series E Preferred Stock to be automatically converted. We may choose to deliver the conversion value in connection with a conversion to investors in cash, shares of common stock, or a combination of cash and common stock.

 

We accounted for the Series E Preferred Stock exchange as an extinguishment transaction pursuant to SEC guidance codified provided by FASB Accounting Standards Codification (“ASC”) in section 260-10-S99-02. SEC guidance indicates when a preferred stock extinguishment has occurred the difference between the fair value of the consideration transferred to the holders of the preferred stock and the carrying amount of that preferred stock on the balance sheet should be subtracted from or added to net income to arrive at income available to common stockholders in the calculation of earnings per share. Accordingly, we recognized a $95.8 million return of dividend that was added to net loss to arrive at net loss available to common stock.

 

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Preferred Stock Dividends

 

Beginning in the third quarter of 2015 all preferred stock dividend declarations and payments have been suspended.  We are not in a position to declare or issue any dividends due to a lack of surplus as defined under Delaware state law. 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.  If we fail to pay dividends for six or more quarterly periods, whether or not consecutive, on our Series C Preferred Stock or Series D Preferred Stock the holders will receive limited voting rights.

 

The following table sets forth information related to the components of Preferred stock, net on our Consolidated Statements of Operations:

 

We reported dividends of $81.2 million on our Consolidated Statements of Stockholders’ Equity (Deficit) for the year ended December 31, 2015, while we reported net preferred stock activity of $69.5 million on our Consolidated Statement of Operations for the year ended December 31, 2015.  The difference between the two reported amounts is $10.5 million of preferred stock dividends in arrears and a $1.2 million dividend payment timing difference.

Common Stock Offering

On March 10, 2015, we closed an underwritten public offering of 12 million shares of our common stock at $ 4.15 per share.  Proceeds after offering expenses totaled approximately $47.5 million. The proceeds were used to repay borrowings under our Senior Credit Facility and for general corporate purposes.

Warrants

In connection with the issuance of the 8.0% Second Lien Notes, we issued a detachable warrant for each $1,000 note. The holder of a warrant has the right to purchase 48.84 shares of our $0.20 par value common stock. The warrants were issued pursuant to a Warrant Agreement, dated March 12, 2015 (the “Warrant Agreement”), with American Stock Transfer & Trust Company LLC. Under the terms of the Warrant Agreement, the Second Lien Notes and the warrants were not separately transferable until the earliest of (i) 365 days after the date on which the warrants were originally issued; (ii) the date on which a registration statement related to the resale of the warrants was declared effective; (iii) the date on which a registration statement with respect to a registered exchange offer for the Second Lien Notes was declared effective; or (iv) in the event of the occurrence of a change of control (as defined in the governing indenture), the date on which requisite notice of such change of control was mailed to the holders of Second Lien Notes. Also, on March 12, 2015, we entered into a Registration Rights Agreement with the Purchaser that provides holders of the warrants certain rights to registration under the Securities Act relating to the Warrants.  Pursuant to the Warrant Registration Rights Agreement, we were obligated to file a shelf registration statement with the SEC within 90 days of March 12, 2015, relating to re-sales of the Warrants.

A Form S-3 was filed with the SEC on May 22, 2015 to register the resale of the warrants and the common stock issuable upon the conversion of such warrants. The Second Lien Notes and warrants became separately transferable on June 4, 2015 when the Form S-3 registration statement related to the resale of the warrants was declared effective by the SEC. The warrants are exercisable upon payment of the exercise price of $4.664 or convertible on a cashless basis as set forth in the agreement governing the warrants. Any warrants not exercised by March 12, 2025 will expire.

Upon issuance, we valued the warrants as a separate financial instrument using the Black-Scholes model and recorded the $15.4 million relative fair value to Additional paid in capital on the Consolidated Balance Sheets.

On October 1, 2015, in connection with the issuance of the 8.875% Second Lien Notes we issued 38,250 warrants. Each warrant is entitled to purchase approximately 156.9 shares of our $0.20 par value common stock for $1.00 per share. As previously stated, the

 

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warrants will not be separately transferable until the earlier of (i) 60 days after the date on which the Warrants are originally issued or (ii) in the event of the occurrence of a change of control, as defined in the governing indenture. At such time, the warrants will become convertible on a cashless basis as set forth in the warrant agreement. Any warrants not exercised in ten years from the date of issuance will expire.  These warrants are not subject to a registration rights agreement.

Conversions to Common Stock

In 2015, we issued 5.2 million shares of our common stock to holders that exercised their conversion rights on $10.4 million face amount of the 2032 Exchange Notes. We recorded the $17.1 million carrying amount of the converted 2032 Exchange Notes to stockholders equity. See Note 4.

In December 2015, we issued 476,800 shares of our common stock to Series E Preferred Stock holders that exercised their conversion rights on approximately 95,000 depositary shares of Series E Preferred Stock.

 

 

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 2015, 2014 and 2013 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.

See Note 4 for further discussion of the embedded derivative associated with the 8.0% Second Lien Notes.

The following table summarizes the gains and losses we recognized on our oil and natural gas derivatives for the years ended December 31, 2015, 2014 and 2013.

 

 

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, 2015, the commodity derivatives we used were in the form of:

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 not have been at risk of losing any fair value amounts had our counterparties as a group been unable to fulfill their obligations as of December 31, 2015 since we did not have a derivative asset on our Consolidated Balance sheets as of December 31, 2015.

As of December 31, 2015, our open positions on our outstanding commodity derivative contracts, all of which were with JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A., were as follows:

 

 

 

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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, 2015 and 2014 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Note 1 “Fair Value Measurement” for our discussion for inputs used and valuation techniques for determining fair values.

 

 

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, 2015 and December 31, 2014.

 

 

 

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, 2015 (in thousands).

 

 

 

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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, 2015, 2014 and 2013, was approximately $1.5 million, $1.4 million and $1.3 million, respectively.

Pipe Contracts— On June 10, 2015, we entered into an eighteen month term agreement with a third party vendor which obligated us to purchase $11.4 million in pipe. We will receive and pay for approximately $0.6 million of pipe each month during the term of the agreement. Our obligation may be reduced subject to the vendor identifying an opportunity to sell the pipe to the open market.  We have taken delivery of seven shipments under this agreement and an $6.8 million commitment remained at December 31, 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 $0.5 million $0.6 million and $0.7 million for 2015, 2014 and 2013, 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.

 

 

NOTE 10—Related Party Transactions

Patrick E. Malloy, III, resigned as Chairman of the Board of Directors of our Company in May 2015. Mr. Malloy 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, the amounts billed and outstanding to MEC for its share of monthly capital and operating costs was less than $0.1 million and was included in trade and other accounts receivable on the consolidated balance sheets. 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 during 2015 through the date of Mr. Malloy resignation from the Board of Directors and for the year ended December 31, 2014 were $0.3 million and $0.4 million, respectively. Revenue distributions for the same periods totaled $0.1 million and $0.5 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, the amounts billed and outstanding to the affiliate for its share of monthly capital and operating costs was less than $0.3 million and was included in trade and other accounts receivable on the consolidated balance sheets. 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, during 2015 through the date of Mr. Malloy resignation from the Board of Directors and for the year ended December 31, 2014, to these affiliates, totaled $0.2 million and $1.2 million, respectively.  Revenue distributions during the same periods totaled $0.2 million and $1.2 million, respectively.

 

 

Note 11 – Dispositions and Acquisitions

 

On September 4, 2015 we closed the sale of our proved reserves and a portion of the associated leasehold in the Eagle Ford Shale Trend located in La Salle and Frio counties in Texas for $118.0 million. We received net proceeds of $110.0 million after closing adjustments based upon an effective date of July 1, 2015. We used the net proceeds from the sale to repay borrowings under our Senior Credit Facility. We recorded a $49.7 million gain on the sale in 2015.

 

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Note 12 – Subsequent Events

 

Exchange Offers

 

On January 26, 2016 we commenced the “Exchange Offers”. The Exchange Offers, are designed to reduce or eliminate the principal amount of our Existing Unsecured Notes and liquidation preference on our Existing Preferred Stock, reduce cash interest expense through the exchange of the Existing Unsecured Notes into common stock, enable us to defer interest on the Second Lien Notes by issuing additional notes in lieu of cash interest and eliminate our dividend obligations for the Existing Preferred Stock.

 

We are conducting the Exchange Offers in response to the current low commodity price environment that has had a significant, adverse impact on the Company. Our ability to make the March 2016 interest payments on our 8.0% Second Lien Notes, 8.875% Second Lien Notes and 2019 Notes and service other debt and fund operations is at significant risk as a result of the sustained low commodity prices and raises substantial doubt about our ability to continue as a going concern. If we are unable to complete the Exchange Offers, and address near-term liquidity needs, we may need to seek relief under the U.S. Bankruptcy Code. This relief may include: (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of the Company’s assets pursuant to section 363(b) of the U.S. Bankruptcy Code and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization (where votes for the plan may be solicited from certain classes of creditors prior to a bankruptcy filing) that the Company would seek to confirm (or “cram down”) despite any classes of creditors who reject or are deemed to have rejected such plan; or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks. See Note 1 “—Recapitalization Plan” for further information.

 

Special Meeting of Shareholders

 

On March 31, 2016, we will hold a special meeting of our stockholders to approve (i) an amendment to our Restated Certificate of Incorporation increasing the number of authorized shares of our Common Stock to 400 million (the “Authorized Share Amendment Proposal”) to allow for the issuance of common stock in the various Exchange Offers in connection with the Recapitalization Plan and (ii) amendments to the Certificate of Designation of each of series of Existing Preferred Stock that would, if approved, allow us to mandatorily convert such series of Existing Preferred Stock into common stock at the rate offered in the applicable Preferred Exchange Offer (each, a “Preferred Stock Amendment Proposal”).  

 

Exercise of Right to Grace Period

 

On March 15, 2016, the Company elected to exercise its right to a grace period with respect to a $5.2 million interest payment due on its 2019 Notes, issued pursuant to the Indenture dated as of March 2, 2011, between the Company, Goodrich Petroleum Company, L.L.C., as subsidiary guarantor, and Wells Fargo Bank, National Association, as trustee (the “2019 Senior Notes Indenture”), a $4.0 million interest payment due on its 8.0% Second Lien Notes, issued pursuant to the Indenture dated as of March 12, 2015, between the Company, Goodrich Petroleum Company, L.L.C., as subsidiary guarantor, and U.S. Bank National Association, as trustee and collateral trustee (the “8.0% Second Lien Indenture”), and a $3.3 million interest payment due on its 8.875% Second Lien Notes, issued pursuant to the Indenture, dated as of October 1, 2015, between the Company, Goodrich Petroleum Company, L.L.C., as subsidiary guarantor, and U.S. Bank National Association, as trustee and collateral trustee (the “8.875% Second Lien Indenture” and, together with the 2019 Senior Notes Indenture and the 8.0% Second Lien Notes Indenture, the “Indentures”). The interest payments were due on March 15, 2016; however, such grace period permits the Company 30 days to make such interest payments before an event of default occurs under the Indentures.

 

The Company believes it is in the best interests of its stakeholders to actively address the Company’s debt and capital structure and is continuing discussions with its creditors and their respective professionals. The Company is continuing to pay suppliers and other trade creditors in the ordinary course of business.

 

 

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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, 2015 and 2014. NSAI prepared the reserves estimates as of December 31, 2013. Approximately 58% and 42% of the proved reserves estimates shown herein at December 31, 2015 have been independently prepared by NSAI and RSC, respectively. NSAI prepared the estimates on all our proved reserves as of December 31, 2015 on our properties other than in the TMS. RSC prepared the estimate of proved reserves as of December 31, 2015 for our TMS properties. Copies of the summary reserve reports of NSAI and RSC for 2015 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 2015. For oil volumes, the average price of $50.28 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For natural gas volumes, the average price of $2.58 per MMBtu is adjusted by lease for energy content, transportation fees, and regional price differentials.  

Capitalized Costs

The table below reflects our capitalized costs related to our oil and natural gas producing activities at December 31, 2015 and 2014 (in thousands):

 

We did not have any capitalized exploratory well costs that were pending the determination of proved reserves as of December 31, 2015 and had $14.5 million as of December 31, 2014. During 2015, none of the December 31, 2014 pending capitalized exploratory well costs were expensed.

 

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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):

 

 

The following table sets forth our net proved oil and natural gas reserves at December 31, 2015, 2014 and 2013 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:

 

 

 

 

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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):

 

 

The estimated future net cash flows are 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.

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):

 

 

 

 

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Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

 

 

 

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 Exchange Act 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 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, 2015, 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 Item 8—Financial Statements and Supplementary Data—Management’s Annual Report on Internal Controls over Financial Reporting” of this Annual Report on Form 10-K.

Attestation Report of the Registered Public Accounting Firm

See “Item 8— Financial Statements and Supplementary Data—Report of Independent Registered Public Accounting Firm” 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.

 

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None.

 

 

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PART III

 

Our executive officers and directors and their ages and positions as of March 30, 2016, are as follows:

 

 

Josiah T. Austin became one of our directors in 2002. 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 Protea Bioscience.

 

Robert T. Barker was appointed Interim Chief Financial Officer in March 2016. He joined the Company in 2007 as the Manager, Financial Reporting and has held various positions within the Accounting Department with increasing responsibility, most recently as Vice President, Controller and Principal Accounting Officer. Mr. Barker has over 30 years of experience in the energy industry. Prior to joining the company, Mr. Barker was Controller for Cygnus Oil and Gas Corporation.  Mr. Barker is a certified public accountant and holds a M. B. A. from the University of Houston.

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 Chairman of the Board of Directors in 2015. He has served as our Chief Executive Officer since 1995 and the Vice Chairman of our Board from 2003 to 2015. 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. He has served as a director since 1995.

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.

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.

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.

Stephen M. Straty is a Managing Director 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,

 

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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 position with the NFL in 1994. Mr. Washington has served on numerous corporate and civic boards, including serving as a director of the former New York Bancorp, a New York Stock Exchange (“NYSE”) listed company. He was elected to the Company’s Board of Directors in 2003.

Additional information required under this “Item 10—Directors, Executive Officers and Corporate Governance,” will be provided in our Proxy Statement for the 2016 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 2016 annual meeting of stockholders to be filed within 120 days from December 31, 2015. 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 2016 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2015.

 

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 2016 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2015.

 

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 2016 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2015.

 

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 2016 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2015.

 

 

 

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PART IV

 

(a)(1) and (2) Financial Statements and Financial Statement Schedules

See “Index to Consolidated Financial Statements” on page 61.

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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SIGNATURES

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 March 30, 2016.

 

POWER OF ATTORNEY

Each person whose signature appears below hereby constitutes and appoints Walter G. Goodrich and Robert T. Barker 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 March 30, 2016.

 

 

 

 

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